Edgar Filing: NuStar Energy L.P.

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-16417

NUSTAR ENERGY L.P.

(Exact name of registrant as specified in its charter)



Delaware		74-2956831
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

19003 IH-10 West		78257
San Antonio, Texas		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code (210) 918-2000

Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partner interests listed on the New York Stock Exchange. 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests listed on the New York Stock Exchange.

Securities registered pursuant to 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:



Large accelerated filer	[X]	Accelerated filer	[ ]

Non-accelerated filer	[ ]	Smaller reporting company	[ ]

		Emerging growth company	[ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

The aggregate market value of the common units held by non-affiliates was approximately $1.8 billion based on the last sales price quoted as of June 29, 2018, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, 2019 was 107,278,252.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the registrant’s 2019 annual meeting of unitholders, expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, are incorporated by reference into Part III to the extent described therein.

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NUSTAR ENERGY L.P.

FORM 10-K

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PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties	3
	Overview	3
	Recent Developments	5
	Organizational Structure	6
	Segments	8
	Employees	16
	Rate Regulation	16
	Environmental, Health, Safety and Security Regulation	16
	Risk Factors	19
	Properties	36

Item 1B.	Unresolved Staff Comments	37

Item 3.	Legal Proceedings	37

Item 4.	Mine Safety Disclosures	37

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	38

Item 6.	Selected Financial Data	41

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	65

Item 8.	Financial Statements and Supplementary Data	67

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133

Item 9A.	Controls and Procedures	133

Item 9B.	Other Information	133

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	134

Item 11.	Executive Compensation	134

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	134

Item 13.	Certain Relationships and Related Transactions and Director Independence	134

Item 14.	Principal Accountant Fees and Services	134

PART IV
Item 15.	Exhibits and Financial Statement Schedules	135

Item 16.	Form 10-K Summary	144

Signatures		145

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PART I

Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions and resources. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions, which may cause actual results to differ materially. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.


ITEMS 1., 1A. and 2.	BUSINESS, RISK FACTORS AND PROPERTIES

OVERVIEW

NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units trade on the New York Stock Exchange (NYSE) under the symbol “NS,” and our fixed-to-floating rate cumulative redeemable perpetual preferred units trade on the NYSE under the symbol “NSprA” for our 8.50% Series A Preferred Units, “NSprB” for our 7.625% Series B Preferred Units and “NSprC” for our 9.00% Series C Preferred Units. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.

We are engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.

We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2018, our assets included approximately 9,800 miles of pipeline and 75 terminal and storage facilities, which provide approximately 88 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:



	Year Ended December 31, 2018
	(Thousands of Dollars)
Pipeline	$	272,695
Storage	$	181,471
Fuels marketing	$	24,440

We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:


•	tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;


•	fees for the use of our terminal and storage facilities and related ancillary services; and


•	sales of petroleum products.

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We strive to increase unitholder value by:


•	enhancing our existing assets through strategic internal growth projects that expand our business with current and new customers;


•	pursuing strategic projects to expand and optimize our existing assets and to construct new assets;


•	improving our operations, including safety and environmental stewardship, cost control and asset reliability; and


•	identifying strategic acquisition targets that meet our financial criteria.

Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).

Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.

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RECENT DEVELOPMENTS

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Merger Sub merged with and into NuStar GP Holdings, with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy became the sole member of NuStar GP Holdings following the Merger on July 20, 2018. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. We issued approximately 13.4 million incremental NuStar Energy common units as a result of the Merger. Please refer to the following two pages for organizational charts at December 31, 2018 and before the Merger and Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion. On June 29, 2018, we also issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC.

Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-mile pipeline and 18 storage tanks, for approximately $37.5 million. The assets acquired and the results of operations are included in our pipeline segment, within the East Pipeline, from the date of acquisition. We accounted for this acquisition as an asset purchase.

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including our St. Eustatius terminal, which experienced the most damage and was temporarily shut down. The damage caused by the Caribbean hurricane resulted in lower revenues for our bunker fuel operations in our fuels marketing segment and lower throughput and associated handling fees in our storage segment in 2017 and in the first quarter of 2018. In 2017, we recorded a $5.0 million loss in “Other income (expense), net” in the consolidated statements of income for property damage at the terminal, which represents the amount of our property deductible under our insurance policy, and we received $12.5 million of insurance proceeds, of which $3.8 million was for business interruption. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal, of which $9.1 million related to business interruption. Although the repairs are not complete, we expect that the costs to repair the property damage at the terminal will not exceed the amount of insurance proceeds received. Please refer to Note 1 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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ORGANIZATIONAL STRUCTURE

As a result of the Merger, NuStar GP Holdings, which indirectly owns our general partner, became a wholly owned subsidiary of ours on July 20, 2018. The following chart depicts a summary of our organizational structure at December 31, 2018:

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The following chart depicts a summary of our organizational structure prior to the Merger on July 20, 2018, which is further described in Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”:

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SEGMENTS

Detailed financial information about our segments is included in Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2018:

PIPELINE

Our pipeline operations consist of the transportation of refined products, crude oil and anhydrous ammonia. As of December 31, 2018, we owned and operated:


•	refined product pipelines with an aggregate length of 3,130 miles and crude oil pipelines with an aggregate length of 2,070 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);


•	a 2,150-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);


•	a 450-mile refined product pipeline originating at Marathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and


•	a 2,000-mile anhydrous ammonia pipeline originating in the Louisiana delta area that travels north through the Midwestern United States to Missouri before forking east and west to terminate in Indiana and Nebraska (the Ammonia Pipeline).

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The following table lists information about our pipeline assets as of December 31, 2018:



			Throughput For the year ended December 31,
Region / Pipeline System	Length	Tank Capacity	2018	2017
	(Miles)	(Barrels)	(Barrels/Day)
Central West System:
McKee System	2,276	—	193,396	171,815
Three Rivers System	373	—	81,174	78,165
Other	481	—	51,130	53,829
Central West Refined Products Pipelines	3,130	—	325,700	303,809
South Texas Crude System	328	2,157,000	144,976	114,920
Other	200	—	70,251	52,969
Eagle Ford System	528	2,157,000	215,227	167,889
McKee System	598	1,039,000	154,718	137,675
Ardmore System	119	824,000	70,967	84,801
Permian Crude System	825	1,000,000	435,743	192,958
Central West Crude Oil Pipelines	2,070	5,020,000	876,655	583,323
Total Central West System	5,200	5,020,000	1,202,355	887,132

Central East System:
East Pipeline	2,150	5,851,000	150,635	139,317
North Pipeline	450	1,494,000	50,180	41,438
Ammonia Pipeline	2,000	—	30,529	32,172
Total Central East System	4,600	7,345,000	231,344	212,927

Total	9,800	12,365,000	1,433,699	1,100,059

Description of Pipelines

Central West System. The Central West System covers a total of 5,200 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,130 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee and Three Rivers refineries.

The crude oil pipelines have an aggregate length of 2,070 miles (Central West Crude Oil Pipelines). Our crude oil pipelines transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the Eagle Ford Shale region to our North Beach marine export terminal and to third-party refineries in Corpus Christi, Texas.

Our Permian Crude System, which is comprised of the assets we acquired in May 2017, together with the assets we have constructed through various expansion projects since the date of the acquisition, consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas. The Permian Crude System is an interconnected system that aggregates receipts from wellhead connection lines into intra-basin trunk lines for delivery to regional hubs and to connections with third-party mainline takeaway pipelines. The system consists of 825 miles of pipelines and covers over 500,000 dedicated acres owned by producers, with approximately 200 well-connection sites. The Permian Crude System also includes two terminals, at Big Spring and Colorado City, as well as several truck stations and other operational storage facilities, with an aggregate storage capacity of 1.0 million barrels.

Central East System. The Central East System covers a total of 4,600 miles and consists of the East Pipeline, North Pipeline and Ammonia Pipeline.

The East Pipeline covers 2,150 miles and transports refined products and natural gas liquids north via pipelines to our terminals and third-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline

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obtain refined products from refineries in Kansas, Oklahoma and Texas. The East Pipeline system includes 18 truck-loading terminals, with storage capacity of approximately 4.4 million barrels and two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.

The North Pipeline originates at Marathon’s Mandan, North Dakota refinery and runs from west to east for approximately 450 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes four truck-loading terminals with storage capacity of approximately 1.5 million barrels.

The 2,000-mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.

Pipeline Operations

We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline. Revenues earned at storage facilities included with these pipeline systems predominately relate to the volumes transported on the pipelines through fees included in the respective pipeline tariff. As a result, these storage facilities are included in this segment instead of the storage segment.

In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) our terminals for further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.

Our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (the DOT), the Environmental Protection Agency (the EPA) and the Department of Homeland Security. Additionally, our pipelines are subject to the respective state jurisdictions. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below for additional discussion.

The majority of our pipelines are common carrier. Common carrier activities are those for which transportation through our pipelines is available to any shipper who requests such services and satisfies the conditions and specifications for transportation. Published tariffs are (i) filed with the FERC for interstate petroleum product shipments, (ii) filed with the relevant state authority for intrastate petroleum product shipments or (iii) regulated by the STB for our Ammonia Pipeline.

We operate our pipelines remotely through an operational technology system called the Supervisory Control and Data Acquisition, or SCADA, system.

Demand for and Sources of Refined Products and Crude Oil

Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand for refined products in the markets served by those pipelines, as well as the ability and willingness of the refiners and marketers with access to the pipelines to supply that demand through our pipelines.

The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for motor fuels fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons, including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and for longer distances.

Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for

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agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall.

Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

The North Pipeline is heavily dependent on Marathon’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Marathon refinery could have a material adverse effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third-party connecting pipelines that receive products originating from Gulf Coast refineries.

Other than the Valero Energy refineries and the Marathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming stable demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.

Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could fluctuate with the price of crude oil. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Eagle Ford System and Permian Crude System. However, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.

Demand for and Sources of Anhydrous Ammonia

The Ammonia Pipeline currently is one of two major anhydrous ammonia pipelines in the United States transporting anhydrous ammonia into the nation’s corn belt and the only one with the connectivity to receive products from outside the United States directly into the system.

Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.

Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.

Customers

Valero Energy, the largest customer of our pipeline segment, accounted for approximately 30% of the total segment revenues for the year ended December 31, 2018. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for more than 10% of the total revenues of the pipeline segment for the year ended December 31, 2018.

Competition and Other Business Considerations

Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other pipeline companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may competitively deliver products in some of the areas served by our pipelines; however, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes.

Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.

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Certain of our crude oil pipelines serve areas and/or refineries that are affected by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.

The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.

Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline, also owned by Magellan, which originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. On January 31, 2019, Magellan announced its plans to discontinue commercial operations of its ammonia pipeline in late 2019. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation also compete with the Ammonia Pipeline under certain market conditions.

STORAGE

Our storage segment consists of facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. On November 30, 2018, we sold our European operations, including six liquids storage terminals in the United Kingdom and one facility in Amsterdam, with total storage capacity of approximately 9.5 million barrels. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.

As of December 31, 2018, we owned and operated:


•	40 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with total storage capacity of 53.8 million barrels;


•	A terminal on the island of St. Eustatius with tank capacity of 14.3 million barrels and a transshipment facility; and


•	A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility.

The following table sets forth information about our terminal and storage facilities as of December 31, 2018:



Facility	Tank Capacity
	(Barrels)
Colorado Springs, CO	328,000
Denver, CO	110,000
Albuquerque, NM	251,000
Rosario, NM	166,000
Catoosa, OK	358,000
Abernathy, TX	160,000
Amarillo, TX	269,000
Corpus Christi, TX	491,000
Corpus Christi, TX (North Beach)	3,339,000
Edinburg, TX	340,000
El Paso, TX (a)	419,000
Harlingen, TX	286,000
Laredo, TX	215,000
San Antonio, TX (b)	375,000
Southlake, TX	569,000
Nuevo Laredo, Mexico	35,000
Central West Terminals	7,711,000

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Facility	Tank Capacity
	(Barrels)
Jacksonville, FL	2,593,000
St. James, LA	9,917,000
Houston, TX	86,000
Texas City, TX (b)	2,964,000
Gulf Coast Terminals	15,560,000

Blue Island, IL	690,000
Andrews AFB, MD (c)	75,000
Baltimore, MD	813,000
Piney Point, MD	5,402,000
Linden, NJ (b)	5,134,000
Paulsboro, NJ	74,000
Virginia Beach, VA (c)	41,000
North East Terminals	12,229,000

Los Angeles, CA	608,000
Pittsburg, CA	398,000
Selby, CA	3,074,000
Stockton, CA	816,000
Portland, OR	1,345,000
Tacoma, WA	391,000
Vancouver, WA (b)	774,000
West Coast Terminals	7,406,000

Benicia, CA	3,683,000
Corpus Christi, TX	4,030,000
Texas City, TX	3,141,000
Refinery Storage Tanks	10,854,000

St. Eustatius, the Netherlands	14,256,000
Point Tupper, Canada	7,778,000
International Terminals	22,034,000

Total	75,794,000


(a)	We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.


(b)	Location includes two terminal facilities.


(c)	Terminal facility also includes pipelines to U.S. government military base locations.

Description of Major Terminal Facilities

St. Eustatius. We own and operate a 14.3 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean Netherlands, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it has the capability to load or unload up to three vessels at a time, including heavily laden ultra large crude carriers, or ULCCs. The facility has a two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring (SPM) buoy with the ability to load and unload two different products at the SPM and segregate various grades of crude and fuel oil to and from the SPM. The fuel oil and petroleum product facilities have in-tank and in-line

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blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit, which is capable of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Refinery Storage Tanks. We own and operate crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, TX and Benicia, CA. Effective January 1, 2017, we lease our refinery storage tanks to Valero Energy in exchange for a fixed fee, whereas we previously earned fees based upon throughput.

St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with certain of the tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal is connected to (i) offshore pipelines in the Gulf of Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian and other domestic shale plays, and (iii) pipelines to refineries in the Gulf Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility that are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.

Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavily laden ULCCs for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services (all of which are considered optional services).

Linden, New Jersey. Our Linden terminal facility includes two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 5.1 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility also has two docks.

Corpus Christi North Beach. We own and operate a 3.3 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and is also connected to a third-party pipeline system, providing our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has access to four docks, including two private docks, and can load crude oil onto ships simultaneously on all four docks. This includes exclusive-use access to the Port of Corpus Christi’s newest crude oil dock, which was completed in September 2018 and is able to accommodate Aframax-class vessels.

Storage Operations

We generate storage segment revenues through fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We lease our Refinery Storage Tanks to Valero Energy in exchange for a fixed fee. Certain of our facilities charge fees to provide marine services, such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Demand for Refined Products and Crude Oil

The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined products. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, in a contango market (when the price of a commodity is expected to exceed current prices), demand for storage services will generally increase.

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Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal.

Customers

We provide storage and terminalling services for crude oil and refined products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. Valero Energy, the largest customer of our storage segment, accounted for approximately 20% of the total revenues of the segment for the year ended December 31, 2018. No other customer accounted for more than 10% of the total revenues of the storage segment for the year ended December 31, 2018.

Competition and Other Business Considerations

Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.

Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.

Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude. Light crude suppliers brought the crude from the Middle East and other foreign regions on very large ships, which are efficient for long routes. These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to most U.S. ports, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.” Both terminals are well-located to provide this service.

As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil, particularly on the U.S. Gulf Coast, has dropped. This reduced demand for imported light crude has, in turn, changed oil trade flow patterns around the world, thereby depressing the demand for break-bulk services. Our St. Eustatius terminal’s location is well-suited to consolidate heavy oil cargos from the small ships used to move heavy crude, from Latin America and other origins, off shore to a large vessel for more efficient transport for long routes, a process referred to as “build bulk,” primarily to Asia. However, recently, the combination of oversupply of storage capacity, decreased demand from backwardated markets, reduced North American crude imports and lower than expected growth in production in Latin America has depressed storage rates in the region.

We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break-bulk or build-bulk services, as demanded by the applicable oil trade flows, now and in the future.

Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

FUELS MARKETING

The fuels marketing segment includes our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations. The results of operations for the fuels marketing segment depend largely on the margin between our

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cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments.

Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. No customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2018.

EMPLOYEES

As of December 31, 2018, we had 1,517 employees.

RATE REGULATION

Several of our pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

The Ammonia Pipeline is subject to regulation by the STB pursuant to the Interstate Commerce Act applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the Ammonia Pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the Ammonia Pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs.

ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION

Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures to comply with the laws and regulations, mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties.

In 2018, our capital expenditures attributable to compliance with environmental regulations were $12.2 million, and we currently project spending to be approximately $14.1 million in this regard in 2019. However, future governmental actions

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could result in these laws and regulations becoming more restrictive, necessitating additional capital expenditures and operating expenses. At this time, we are unable to estimate the effect on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. In addition, while we believe that we are in substantial compliance with the environmental, health, safety and security laws and regulations applicable to our operations, risks of additional compliance expenditures, expenses and liabilities are inherent within the industry. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.

Discussed below are the primary U.S. environmental, health, safety and security laws applicable to our operations. Compliance with or violations of any of these laws and related regulations could result in significant expenditures, expenses and liabilities.

OCCUPATIONAL SAFETY AND HEALTH

We are subject to the Occupational Safety and Health Act, as amended, and analogous or more stringent international, state and local laws and regulations for the protection of worker safety and health. In addition, we have operations subject to the Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes which involve certain chemicals at or above specified thresholds.

FUEL STANDARDS AND RENEWABLE ENERGY

International, federal, state and local laws and regulations regulate the fuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require, subsidize or encourage the purchase and use of renewable energy, electric battery-powered motor vehicle engines and alternative fuels, such as biodiesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of biofuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.

HAZARDOUS SUBSTANCES & HAZARDOUS WASTE

The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a

facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.

We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Our current operating and disposal practices comply with applicable laws, regulations and industry standards, and we believe our past practices complied at the time. Despite our compliance, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including regarding clean up levels, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures.

The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.

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AIR

The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air. These laws and regulations generally require permits issued by applicable federal or state authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.

WATER

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.

PIPELINE AND OTHER ASSET INTEGRITY, SAFETY AND SECURITY

Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity and safety, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have marine terminal operations subject to Coast Guard safety, integrity and security regulations and standards. We also have operations subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards and Transportation Security Administration’s Pipeline Security Guidelines. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

While we are not currently required to implement specific governmental regulatory protocols for the protection of our computer-based systems and technology from cyber threats and attacks, proposals to do so are being considered by a number of U.S. governmental departments and agencies, including the Department of Homeland Security. We currently have our own cybersecurity programs and protocols in place; however, we cannot guarantee their effectiveness, and successful penetration of our critical systems could have a material effect on our operations and those of our customers and vendors.

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RISK FACTORS

RISKS RELATED TO OUR BUSINESS

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.

The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:


•	throughput volumes transported in our pipelines;


•	storage contract renewals or throughput volumes in our terminals and storage facilities;


•	tariff rates and fees we charge and the revenue we realize for our services;


•	demand for and supply of crude oil, refined products and anhydrous ammonia;


•	the effect of worldwide energy conservation measures;


•	our operating costs;


•	the costs to comply with environmental, health, safety and security laws and regulations;


•	weather conditions;


•	domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;


•	prevailing economic conditions; and


•	the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.

Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:


•	our debt service requirements and restrictions on distributions contained in our current or future financing agreements;


•	our capital expenditures;


•	issuances of debt and equity securities and ability to access the capital markets;


•	fluctuations in our working capital needs;


•	adjustments in cash reserves made by our board of directors, in its discretion; and


•	the sources of cash used to fund our acquisitions, if any.

Moreover, the total amount of cash that we have available for distribution to common unitholders is further reduced by the required distributions with respect to the preferred units.

It is possible that one or more of the factors listed above may serve to reduce our available cash to such an extent that we could be rendered unable to pay distributions at the current level or at all in a given quarter. Furthermore, cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items; as a result, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.

As of December 31, 2018, our consolidated debt was $3.1 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, it is possible that any material increase to our debt or other negative financial factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us to access the capital markets. In February 2018, Moody’s Investors Service, Inc. downgraded our credit rating from Ba1 to Ba2, which increased the interest rate on amounts borrowed under our credit facilities. Any additional downgrades in our credit ratings in the future could result in further increases to the interest rate on our revolving credit agreement, significantly increase our capital costs, reduce our liquidity and adversely affect our ability to raise capital in the future.

Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the revolving credit agreement generally requires us to maintain, as of the end of each rolling period of four quarters, a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the revolving credit agreement) not to exceed 5.00-to-1.00, except in specific circumstances, including acquisitions for aggregate net consideration of at least $50 million, when we are permitted to maintain a consolidated debt coverage ratio of up to 5.50-to-1.00 for two rolling periods, as provided in the revolving credit agreement. Our revolving credit agreement also requires us to maintain a minimum consolidated interest coverage ratio (as defined in the revolving credit agreement) of at least 1.75-to-1.00 for each rolling period of four quarters. Failure to comply with any of the revolving credit agreement restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage

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ratio requirements would constitute an event of default and could result in acceleration of our obligations under the revolving credit agreement and possibly other agreements. Future financing agreements we may enter into may contain similar or more restrictive covenants than those we have negotiated for our current financing agreements.

Our accounts receivable securitization program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the related receivables financing agreement (pursuant to which we are the initial servicer and performance guarantor) provides for acceleration of amounts owed upon the occurrence of certain specified events.

Our debt service obligations, restrictive covenants and maturities resulting from our leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions, limit our flexibility in planning for, or reacting to, changes in our business and industry and place us at a competitive disadvantage compared to competitors with proportionately less indebtedness. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. Also, if any of our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to our unitholders.

Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our units.

Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs.

From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the market. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially, possibly at a time when the availability of funds from these markets has diminished. The cost of obtaining funds from the credit markets may increase as interest rates increase and tighter lending standards are enacted, and lenders may refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers.

In addition, lending counterparties under our existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new financing or funding will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities, any of which could have a material adverse effect on our revenues and results of operations.

A significant portion of our debt matures over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could limit our refinancing options.

A significant portion of our debt is set to mature within the next five years, including our revolving credit facility. We may not be able to refinance our maturing debt on commercially reasonable terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the then-current state of the banking and capital markets in the United States.

Increases in interest rates could adversely affect our business and the trading price of our units.

We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments. At December 31, 2018, we had approximately $3.1 billion of consolidated debt, of which $1.5 billion was at fixed interest rates and $1.6 billion was at variable interest rates. Additionally, at December 31, 2018, the aggregate notional amount of our interest rate swap arrangements was $250.0 million, which may expose us to risk of financial loss. Prior ratings downgrades on our existing indebtedness caused interest rates under certain of our debt instruments to increase, and any future downgrades may further increase the interest rate on our revolving credit agreement. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.

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The majority of our variable-rate indebtedness uses LIBOR as a benchmark for establishing the rate. LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform. These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. The consequences of these developments cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness.

Furthermore, we have historically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through debt or equity offerings. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.

Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.

Continued low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.

In late 2014, the price of crude oil fell precipitously and did not begin to recover until 2018, and then only to approximately three-quarters of 2014 highs. During fourth quarter 2018 and since, prices again fell into the $40s and $50s per barrel. During periods of sustained low prices, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners tend to benefit from lower crude prices, to the extent that they are able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products. However, as inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude oil prices.

While only a portion of our total business is directly affected by the price of crude, low crude oil prices can slow economic growth overall, and an economic downturn could have a negative impact on our results of operations and cash flow and, by extension, our ability to make cash distributions to our unitholders.

An extended period of reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions to our unitholders.

Although we enter into throughput and deficiency agreements to protect against near-term fluctuations whenever possible, our business is ultimately dependent upon the long-term demand for and supply of the crude oil and refined products we transport in our pipelines and store in our terminals. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil. Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:


•	a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;


•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;


•	an increase in aggregate automotive engine fuel economy;


•	new regulations or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;


•	the increased use of alternative fuel sources;


•	an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and drive demand for alternative products; and


•	a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:


•	prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;


•	a lack of drilling services or equipment available to producers to accommodate production needs;

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•	changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and


•	macroeconomic forces affecting, or actions taken by, foreign oil and gas producing nations that impact supply of and prices for crude oil and refined products.

Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.

Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a commitment from a customer that sufficiently exceeds our cost of capital to justify the project cost, predictions of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forego certain investments and to lose opportunities to competitors who make investments based on different predictions. If we are unable to acquire new assets, due either to high prices or a lack of attractive synergistic targets, our future growth could be limited. In addition, our future growth will be limited if we are unable to develop additional expansion projects, implement business development opportunities and finance such activities on economically acceptable terms, which could adversely impact our results of operations and cash flows and, accordingly, result in reduced distributions over time.

Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash flows.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:


•	non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;


•	denial or delay in issuing requisite regulatory approvals and/or permits;


•	protests and other activist interference with planned or in-process projects;


•	unplanned increases in the cost of construction materials or labor;


•	disruptions in transportation of modular components and/or construction materials;


•	severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;


•	shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or


•	market-related increases in a project’s debt or equity financing costs.

While we incur financing costs during the planning and construction phases of our projects, a project does not generate expected operating cash flows until it is completed, if at all. Additionally, our forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil and refined products, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.

As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or could be delayed. In turn, this could have a negative impact on our results of operations and cash flow and our ability to make cash distributions to our unitholders.

If we are unable to retain or replace current customers and existing contracts to maintain utilization of our pipeline and storage assets at current or more favorable rates, our revenue and cash flows could be reduced to levels that could adversely affect our ability to make quarterly distributions to our unitholders.

Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew or enter into new contracts or our storage customers’ material reduction of utilization under existing contracts could result from many factors, including:


•	continued low crude oil prices;


•	a material decrease in the supply or price of crude oil;


•	a material decrease in demand for refined products in the markets served by our pipelines and terminals;


•	political, social or economic instability in another country impacting a customer based there;


•	competition for customers from companies with comparable assets and capabilities;


•	scheduled turnarounds or unscheduled maintenance at refineries we serve;


•	operational problems or catastrophic events affecting our assets or a refinery we serve;

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•	environmental proceedings or other litigation that compel the cessation of all or a portion of the operations of our assets or a refinery we serve;


•	increasingly stringent environmental, health, safety and security regulations;


•	a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; or


•	a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could reduce our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.

We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also may have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry, some of our customers may be reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts in the future. Our inability to renew or replace our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions could have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.

Our operations are subject to operational hazards and interruptions, and we cannot insure against and/or predict all potential losses and liabilities that might result therefrom.

Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms and floods), accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. In addition, many scientists hypothesize that global climatic changes are occurring that are likely to increase the number and severity of hurricanes and other damaging weather conditions. These events might result in a loss of life or equipment, injury or extensive property damage, as well as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase substantially; therefore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Certain insurance coverage could become subject to broad exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. If we were to incur a significant liability for which we are insufficiently insured, such a liability could have a material adverse effect on our financial position.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.

In addition, nonperformance by vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding derivatives could expose us to additional interest rate or commodity price risk. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we may not always be able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.

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We could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims related to the operation of our assets and the services we provide to our customers.

Certain of the products we store and transport are produced to precise customer specifications. If we fail to maintain the quality and purity of the products we receive and/or a product fails to perform in a manner consistent with the quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also could face other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. A successful claim or series of claims against us could result in unforeseen expenditures and a loss of one or more customers.

Our policies and practices to manage risk exposures cannot eliminate all risk, and noncompliance with our policies could result in significant financial losses.

We have implemented policies and practices that are designed to minimize risk, including credit risk, commodity price risk and operational risk. These policies and practices cannot, however, eliminate all such risks, and any policy only reduces risk to the extent affected parties comply thereunder. We cannot make any assurances that we will detect and prevent all violations of our policies and practices, particularly if deception, collusion or other intentional misconduct is involved. Any violations of these policies or practices by our employees or agents could result in significant financial losses.

An impairment of goodwill or long-lived assets could reduce our earnings.

We have recorded $1.0 billion of goodwill and $5.0 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net, as of December 31, 2018. U.S. generally accepted accounting principles requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital. There was no impairment recorded for goodwill or other long-lived assets for the years ended December 31, 2018 or 2017.

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

We rely on our information technology infrastructure to process, transmit and store electronic information. Additionally, we rely on our operational technology systems, as well as our information technology systems, to safely operate our assets. The security of our information networks and systems is critical to our operations and business strategy. Despite our security measures, we may suffer a cybersecurity incident due to attacks from a variety of external threat actors, internal employee error or malfeasance, or even cybersecurity incidents suffered by our managed service providers or other vendors. This may lead to the compromise of confidential business information, personal information or other data assets, as well as operational system disruptions. In recent years, there has been a rise in the number of cyberattacks on network and information systems generally, by both state-sponsored and criminal organizations and, as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, damage to our reputation, loss of customers or revenues and potential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if operational systems are breached or an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.

Although we believe that we have robust cybersecurity procedures and other safeguards in place, as threats continue to evolve and cybersecurity, data protection laws and regulations continue to develop, we may be required to expend additional resources to continue to enhance our information security, data protection and business continuity measures and/or to investigate and remediate information security vulnerabilities.

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Acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions effectively into our existing operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and operations. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

Part of our overall business strategy includes acquiring additional assets that complement our existing asset base and distribution capabilities or provide entry into new markets. We may not be able to identify suitable acquisitions, or we may not be able to purchase or finance any acquisitions on terms that we find acceptable. Additionally, we compete against other companies for acquisitions, and we may not be successful in the acquisition of any assets or businesses appropriate for our growth strategy.

Even if we do consummate acquisitions that we believe will increase distributable cash flow, these acquisitions may nevertheless result in a decrease in distributable cash flow. Any acquisition involves potential risks, including, among other things:


•	we may not be able to obtain the cost savings and financial improvements we anticipate or acquired assets may not perform as we expect;


•	we may not be able to successfully integrate the assets, management teams or employees of the businesses we acquire with our assets and management team, or such integration may be significantly delayed;


•	we may fail or be unable to discover some of the liabilities of businesses that we acquire, including liabilities resulting from a prior owner’s noncompliance with applicable federal, state or local laws;


•	we may have assumed prior known or unknown liabilities for which we may not be indemnified or have adequate insurance;


•	acquisitions may divert the attention of our senior management from focusing on our core business;


•	we may experience a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; and


•	we may face the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth.

We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.

A portion of our revenues are generated from our assets located outside of the United States. Our operations are subject to various risks unique to each country in which we operate that could have a material adverse effect on our business, results of operations and financial condition. With respect to any particular country, these risks may include political and economic instability, including: civil unrest, war and other armed conflict; inflation; and currency fluctuations, devaluation and conversion restrictions. We are also exposed to the risk of governmental actions that may: limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on our ability to conduct business with certain customers or persons; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, and other foreign laws prohibiting corrupt payments, as well as import and export regulations.

We also have assets in, or have had customers based in, certain developing markets, such as Mexico, and in challenged markets, such as Venezuela, and the nature of these markets presents a number of risks. In addition, due to the unsettled political conditions in many oil-producing countries, our operations may be subject to the adverse consequences of war, civil unrest, strikes, currency controls and governmental actions. Deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which we do business, or affecting a customer with whom we do business, as well as difficulties in staffing and managing foreign operations, may adversely affect our operations or financial results. For example, PDVSA, which was a significant customer of our terminal facility in St. Eustatius, has been affected by the political, social and economic instability in Venezuela in recent years, as well as the negative effects from sanctions implemented by the United States and others, which has undermined PDVSA’s ability to operate and to pay its creditors timely.

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We are subject to laws and sanctions implemented by the United States and foreign jurisdictions where we do business that may restrict the type of business we are permitted to conduct with certain entities, including PDVSA, restrict our activities in certain countries, or even restrict the services we may provide with respect to crude oil or other products produced in certain countries or by certain entities. In 2017, the United States and the European Union imposed sanctions restricting certain types of activities involving Venezuela and PDVSA. On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC) added PDVSA to its List of Specially Designated Nationals and Blocked Persons (the SDN List), which, in effect, prohibits U.S. persons from engaging in most activities involving PDVSA, its property, and its interest in property, after a short wind down period. The inclusion of PDVSA on the SDN List prevents us from continuing our existing business with PDVSA. Consequently, we completed a wind down of all operations and agreements involving PDVSA on February 26, 2019, consistent with applicable laws.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

Like other pipeline and storage logistics services providers, certain of our pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that we have obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of our rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of property rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

In addition, the construction of expansions or other changes to our existing assets may require us to obtain new rights-of-way or property rights prior to construction. We may be unable to obtain such rights-of-way or other property rights to connect new supplies to our existing pipelines, storage terminals or other facilities or to capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or other property rights or to renew existing rights-of-way or property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest and responsive government intervention have recently made it more difficult for some energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of one or more key executive officers could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.

Additionally, our ability to hire, train and retain qualified personnel continues to be important and could become more challenging in competitive energy industry market conditions. In regions experiencing rapid growth, such as the Permian Basin, and at times when general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and midstream companies’ needs for the same personnel increases. Our ability to continue our current level of service to our customers could be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We may have liabilities from our assets that preexist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.

Assets we acquired may have associated liabilities that precede our ownership but for which we are not indemnified by the seller responsible. In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products, and releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial

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position and results of operations. Conversely, if future releases or other liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.

Climate change and fuels legislation and other regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.

In response to scientific studies asserting that emissions of certain “greenhouse gases” such as carbon dioxide and methane may be contributing to warming of the Earth’s atmosphere, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. To the extent the United States and other countries impose climate change regulations on the oil industry, it could have an adverse direct or indirect effect on our business.

Passage of climate change or fuels legislation or other regulatory initiatives in fuel efficiency, fuel additives, renewable fuels and other areas in which we conduct business could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas or other emissions, pay any taxes related to our greenhouse gas or other emissions or administer and manage emissions programs.

In addition, certain of our blending operations can result in requirements to purchase renewable energy credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and operations.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the other countries in which we operate, relating to environmental, health, safety and security that could require us to make substantial expenditures.

Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk that these products may be released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, certain of our pipeline facilities may be subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies. In recent years, increased regulatory focus on pipeline integrity and safety has resulted in various proposed or adopted regulations. The implementation of these regulations, and the adoption of future regulations, could require us to make additional capital expenditures, including to install new or modified safety measures, or to conduct new or more extensive maintenance programs.

Current and future legislative action and regulatory initiatives could also result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment or release prevention and containment systems that could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.

We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.

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Our interstate common carrier pipelines are subject to regulation by the FERC.

The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier pipelines. FERC regulations require that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preference with respect to any shipper. Under the ICA, the FERC or shippers may challenge our pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of amounts collected in excess of amounts generated by the just and reasonable rate determined by the FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, any complaining shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011, the index was measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, which will end on June 30, 2021, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. It is possible that the index may result in a negative adjustment in some years, in which case we are required to reduce any rates that exceed the new maximum allowable rate. It is also possible that changes in the index might not be large enough to fully reflect actual increases in our costs. Some of our newer projects that have involved an open season include negotiated indexation rate caps that restrict the index rate increases that can be made during the term of the applicable transportation service agreements.

In October 2016, the FERC initiated an Advance Notice of Proposed Rulemaking (ANOPR) to determine whether to require oil pipeline companies to file cost and revenue data for each of the company’s pipeline systems, with the definition of such systems also part of the ANOPR. Among other things, the ANOPR also proposed that index rate adjustments be capped or prohibited under certain circumstances and that ceiling rates be capped under certain circumstances. In particular, the FERC has proposed denying index increases to a pipeline if its FERC Form No. 6 reflects revenues in excess of total cost of service by 15% for both of the prior two years or the proposed index increase would exceed by 5% the pipeline’s annual cost changes. The FERC also has proposed requiring pipelines to file additional information for crude and product pipelines, non-contiguous systems and major pipeline systems. The ANOPR remains pending and FERC has taken no action with regard to the ANOPR since receiving initial comments. The methodologies proposed in the ANOPR, if adopted, could result in changes in our revenue that do not fully reflect changes in costs we incur to operate and maintain our pipelines. They also could lead to an increase in rate litigation at the FERC.

In March 2018, the FERC, in its Revised Policy Statement on the Treatment of Income Taxes (Revised Policy), reversed its long-standing policy that allowed master limited partnership (MLP) pipelines to include in their cost of service an income tax allowance (ITA) if they could demonstrate that the ultimate pipeline owners have an actual or potential income tax liability on such income. The FERC stated that the reversal was required by a July 2016 D.C. Circuit Court of Appeals decision that found the FERC had failed to demonstrate that there is no double recovery of taxes for partnerships that receive an income tax allowance in addition to the return they receive through the rate of return on equity. In July 2018, in an order on rehearing, the FERC modified the Revised Policy by providing MLP pipelines with the opportunity to argue for inclusion of an ITA on a case-by-case basis, as opposed to having no opportunity to recover an ITA. The order on rehearing also allowed pipelines that will no longer recover an ITA to eliminate previously Accumulated Deferred Income Tax from cost of service, instead of flowing those amounts back to ratepayers, which has the effect of increasing a pipeline’s cost of service. Petitions for review of the Revised Policy and order on rehearing have been filed and are currently pending in the D.C. Circuit Court of Appeals.

The Revised Policy and order on rehearing do not impact market-based rates or settlement rates, and have no immediate impact on indexed rates, based on the fact that the current index will remain in effect through June 30, 2021. However, following issuance of the Revised Policy, the FERC now requires liquids pipelines organized as MLPs to eliminate the MLP ITA in their Form No. 6, page 700 reporting. The FERC has stated that it will incorporate the effects of this change to the page 700 data when it commences its next five-year review of the oil pipeline index level in 2020, for rates that will take effect on July 1, 2021. The FERC has not yet commenced this proceeding.

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Changes to FERC rate-making principles or pronouncements could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions to our unitholders.

If the FERC’s ratemaking methodologies change, such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements. We believe our rates are consistent with FERC statutory and regulatory requirements, but challenges to our rates could be filed with the FERC and FERC decisions resulting from those challenges could reduce our rates and adversely affect our cash flows. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.

The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.

The Ammonia Pipeline is subject to regulation by the STB, which is part of the DOT. The Ammonia Pipeline’s rates, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, our Ammonia Pipeline may not subject a shipper to unreasonable discrimination.

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2018, our power costs equaled approximately $56.4 million, or 11.6% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarily use natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Terrorist attacks and the threat of future attacks worldwide, as well as continued hostilities in the Middle East or other sustained military campaigns, may adversely impact our results of operations.

The United States Department of Homeland Security has identified pipelines and other energy infrastructure assets as ones that might be specific targets of terrorist organizations. These potential targets might include our pipeline systems, storage facilities or operating systems and may affect our ability to operate or control our pipeline and storage assets. Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, instability in the financial markets that could restrict our ability to raise capital and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an attack.

Hedging transactions may limit our potential gains or result in significant financial losses.

While intended to reduce the effects of volatile commodity prices, hedging transactions, depending on the hedging instrument used, may limit our potential gains if petroleum product prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

The accounting standards regarding hedge accounting are complex and, even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. It is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices, and our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.

Our purchase and sale of petroleum products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.

Although our marketing and trading of petroleum products represent a small percentage of our overall business, these activities expose us to some commodity price volatility risk for the purchase and sale of petroleum products, including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis risk and may be required to post cash collateral under our hedging arrangements. We also may be exposed to inventory and financial liquidity risk due to the inability to trade certain products or rising costs of carrying some inventories. Further, our marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.

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Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility, and there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception and other intentional misconduct are involved.

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to disclose material changes made in our internal controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable and timely financial reports. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404.

For the foregoing reasons, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make distributions to our unitholders.

RISKS INHERENT IN AN INVESTMENT IN US

As a master limited partnership, we do not have the same flexibility as corporations and other types of organizations may have to accumulate cash and equity and prevent illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs, debt service requirements and payments with respect to our preferred units. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organizations, including most traditional public corporations. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations.

Additionally, the value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue more equity to recapitalize.

Our cash distribution policy may limit our growth.

In accordance with the terms of our partnership agreement, we distribute our available cash to our common unitholders each quarter. In determining the amount of cash available for distribution, we set aside cash reserves, which we use to fund our growth capital expenditures. Additionally, we historically have relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund our strategic capital expenditures and acquisitions. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level.

Unitholders have limited voting rights, and our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of any class of our units.

Unlike holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.

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We may issue additional equity securities, including equity securities that are senior to the common units, which would dilute our unitholders’ existing ownership interests.

Our partnership agreement allows us to issue additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or pari passu with, our preferred units. There is no limit on the total number of equity securities we may issue. If we issue additional equity securities, the proportionate partnership interest of our existing common unitholders and the relative voting strength of the previously outstanding common units and Series D Preferred Units will decrease. Any additional issuance may increase the risk that we will be unable to maintain or increase our per common unit distribution level.

With the consent of a majority of the Series D Preferred Units, we may issue an unlimited number of units that are senior to the common units and pari passu with our preferred units. However, in certain circumstances, we may be required to obtain the approval of a majority of each class of our preferred units before we could issue equity securities that are pari passu with our preferred units.

Our issuance of additional units or other equity interests of equal or senior rank will have the following effects:


•	our unitholders’ proportionate ownership interest in us will decrease;


•	the amount of cash available for distribution on each unit may decrease;


•	the ratio of taxable income to distributions may increase;


•	the relative voting strength of each previously outstanding unit may be diminished; and


•	the market price of our common units and preferred units may decline.

Holders of our Series D Preferred Units generally have the same voting rights as holders of our common units and generally vote on an as-converted basis with the holders of our common units as a single class. Although holders of our other preferred units also have voting rights, such rights are limited to certain matters and require that such holders vote as a separate class with all other series of our equally ranked securities that may be issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the holders of such future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of the preferred units are entitled to vote.

The issuance of additional units of equal or senior rank to the preferred units (including additional preferred units of the same series) would dilute the interests of the holders of the preferred units. Furthermore, any issuance of (a) equity securities of any class or series that ranks equally with the preferred units as to (i) the payment of distributions or (ii) the amounts payable upon a liquidation event (including additional preferred units of the same series) or (b) equity securities with terms expressly made senior to the preferred units as to (i) the payment of distributions or (ii) amounts payable upon a liquidation event or additional indebtedness, could affect our ability to pay distributions on, redeem or pay the liquidation preference on the preferred units.

Our partnership agreement contains limited protections for the holders of our preferred units (other than Series D Preferred Units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of the preferred units.

Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our preferred units in any distribution period, we will be unable to declare or pay distributions on our common units until all unpaid preferred unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.

Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D Preferred Units for three consecutive distribution periods, the holders of our Series D Preferred Units have certain additional rights until such distributions are paid, including the right to convert the Series D

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Preferred Units into common units, the right to appoint one director to our board of directors and the right to approve certain indebtedness, acquisitions or asset sales. The preferences and privileges of our preferred units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business or that we have not complied with applicable statutes, which may have an impact on the cash we have available to make distributions.

Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that actions of a unitholder constituted participation in the “control” of our business.

Under Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act) provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.

Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under Section 17-804 of the Delaware Act.

A purchaser of our common or preferred units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or preferred units at the time it became a limited partner and, for unknown obligations, if the liabilities could be determined from our partnership agreement.

Unitholders may be required to sell their units to our general partner at an undesirable time or price.

If at any time less than 20% of the outstanding units of any class (other than our preferred units) are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We currently list our common units on the NYSE under the symbol “NS” and certain of our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or preferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements.

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TAX RISKS TO OUR UNITHOLDERS

If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.

Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes or an increase in the existing tax rates would substantially reduce the cash available for distribution to our unitholders. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

The Tax Cuts and Jobs Act enacted December 22, 2017 made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including changes to the tax rate on a unitholder’s allocable share of income from the publicly traded partnership. Unitholders should consult their tax advisor regarding the impact of the Tax Cuts and Jobs Act (and any other applicable tax laws, rules and regulations) on us or an investment in our units.

Any changes to the federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Cuts and Jobs Act) may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. We are unable to predict whether any additional changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may elect to either pay the taxes directly to the IRS or to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.

Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their respective share of our taxable income.

Tax gain or loss on the disposition of our units could be different than expected.

If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect, become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, a deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” Recently issued proposed regulations would institute a broad definition of interest, treating certain amounts, including amounts paid as guaranteed payments for the use of capital with respect to our preferred units, as business interest subject to the limitation. This limitation is applied at the entity level for partnerships. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Any interest disallowed at the partnership level may be carried forward and deducted in future years by a unitholder from his share of our “excess taxable income,” which is generally equal to the excess of 30% of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subject to certain restrictions.

Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.

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Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (effectively connected income). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, pending promulgation of regulations or other guidance. Non-U.S. unitholders should consult a tax advisor before investing in our units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of our common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The U.S. Treasury Department and the IRS issued final regulations adopting a similar monthly convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ tax returns without the benefit of additional deductions.

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A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of preferred units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Although a holder of preferred units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.

The Tax Cuts and Jobs Act allows individuals and other non-corporate owners of interests in a publicly traded partnership to take a deduction equal to 20% of their allocable share of the partnership’s income that is “qualified publicly traded partnership income.” However, under recently issued final Treasury regulations, income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction. As a result, distributions on the preferred units will be taxable to holders of preferred units as ordinary income that is not eligible for the 20% deduction for qualified publicly traded partnership income.

A holder of preferred units will be required to recognize gain or loss on a sale of preferred units equal to the difference between the amount realized by such holder and tax basis in the preferred units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of preferred units to acquire such preferred unit. Gain or loss recognized by a holder of preferred units on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Distributions to non-U.S. holders of preferred units will be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of preferred units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of preferred units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our preferred units, pending promulgation of regulations or other guidance. Additionally, the treatment of guaranteed payments for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.

All holders of our preferred units are urged to consult a tax advisor with respect to the financial consequences of owning our preferred units.

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PROPERTIES

Our principal properties are described above under the caption “Segments,” and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our normal business operations, including regulatory and environmental matters. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.

We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal proceedings as a result of our ordinary business activity.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Unit Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 15, 2019, we had 427 holders of record of our common units. During 2018, the board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution, which was paid on May 14, 2018. The following table presents the amount, record date and payment date of the quarterly cash distributions on our common units with respect to 2018 and 2017:



	Cash Distributions
	Amount Per Common Unit		Record Date	Payment Date
Year 2018
4th Quarter	$	0.60	February 8, 2019	February 13, 2019
3rd Quarter	$	0.60	November 8, 2018	November 14, 2018
2nd Quarter	$	0.60	August 7, 2018	August 13, 2018
1st Quarter	$	0.60	May 8, 2018	May 14, 2018
Year 2017
4th Quarter	$	1.095	February 8, 2018	February 13, 2018
3rd Quarter	$	1.095	November 9, 2017	November 14, 2017
2nd Quarter	$	1.095	August 7, 2017	August 11, 2017
1st Quarter	$	1.095	May 8, 2017	May 12, 2017

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and, prior to the merger with our general partner, to our general partner each quarter. This term is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors, subject to requirements for distributions for our preferred units. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.

General Partner Distributions

Prior to the merger with our general partner, our Available Cash was distributed based on the percentages shown below:



	Percentage of Distribution
Quarterly Distribution Amount Per Common Unit	Common Unitholders	General Partner Including Incentive Distributions
Up to $0.60	98%	2%
Above $0.60 up to $0.66	90%	10%
Above $0.66	75%	25%

Our general partner’s incentive distributions totaled $45.7 million for the year ended 2017. The general partner did not receive incentive distributions for 2018 because the distribution declared for the first quarter was $0.60 per common unit, which was below the amount necessary to receive incentive distributions. Furthermore, because the merger was effective prior to the record date for the second quarter distribution, the general partner received no distributions after the first quarter distribution. Pursuant to the merger agreement discussed in Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” and at the effective time of the merger, our partnership agreement was amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest.

Due to the impact of the incentive distributions, the general partner’s share of our aggregate distributions for the year ended December 31, 2017 was 11.9%. In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuance of the Series B Preferred Units described below and our acquisition of Navigator

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Energy Services, LLC to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the acquisition agreement, starting with the distributions for the second quarter of 2017.

Preferred Unit Distributions

The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units:



Units	Fixed Distribution Rate Per Annum (as a Percentage of the $25.00 Liquidation Preference Per Unit)	Fixed Distribution Rate Per Unit Per Annum		Fixed Distribution Per Annum		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
				(Thousands of Dollars)
Series A Preferred Units	8.50%	$	2.125	$	19,253	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	7.625%	$	1.90625	$	29,357	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	9.00%	$	2.25	$	15,525	December 15, 2022	Three-month LIBOR plus 6.88%

The distribution rate on our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) is (i) 9.75% per annum ($57.6 million) for the first two years; (ii) 10.75% per annum ($63.4 million) for years three through five; and (iii) the greater of 13.75% per annum ($81.1 million) or the distribution per common unit thereafter.

Distributions on the preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The preferred units rank equal to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation. Please see Notes 19 and 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on distributions to our preferred unitholders.

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Performance Graph

The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively. The stock or unit price performance included in this graph is not necessarily indicative of future stock or unit price performance.

The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 2013, and its relative performance is tracked through December 31, 2018.



	12/13	12/14	12/15	12/16	12/17	12/18
NuStar Energy L.P.	100.00	122.10	91.73	126.25	84.24	65.60
S&P 500 Index	100.00	113.69	115.26	129.05	157.22	150.33
Alerian MLP Index	100.00	104.80	70.65	83.58	78.13	68.43

Sales of Unregistered Securities

During the fourth quarter of 2018, NuStar Energy issued an aggregate of 18,234 common units in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.

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ITEM 6. SELECTED FINANCIAL DATA

The following table contains selected financial data derived from our audited financial statements:



	Year Ended December 31,
	2018			2017		2016		2015		2014
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues (a)	$	1,961,757		$	1,814,019	$	1,756,682	$	2,084,040	$	3,075,118
Operating income	$	363,563		$	336,278	$	359,109	$	390,704	$	346,901
Income from continuing operations (b)	$	205,794		$	147,964	$	150,003	$	305,946	$	214,169
(Loss) income from continuing operations per common unit (b)	$	(2.77	)	$	0.64	$	1.27	$	3.29	$	2.14
Cash distributions per unit applicable to common limited partners (c)	$	2.40		$	4.38	$	4.38	$	4.38	$	4.38

	December 31,
	2018			2017 (d)		2016		2015		2014
	(Thousands of Dollars)
Balance Sheet Data:
Property, plant and equipment, net	$	4,288,622		$	4,300,933	$	3,722,283	$	3,683,571	$	3,460,732
Total assets	$	6,349,140		$	6,535,233	$	5,030,545	$	5,125,525	$	4,918,796
Long-term debt, less current portion	$	3,111,996		$	3,263,069	$	3,014,364	$	3,055,612	$	2,749,452
Total partners’ equity	$	2,257,731		$	2,480,089	$	1,611,617	$	1,609,844	$	1,716,210

(a)

On January 1, 2018, we adopted Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC Topic 606) using the modified retrospective method and applying ASC Topic 606 to all revenue contracts with customers. Results for reporting periods beginning after January 1, 2018 are presented under ASC Topic 606. In accordance with the modified retrospective approach, prior period amounts were not adjusted and are reported under ASC Topic 605, “Revenue Recognition.”

Declines in revenues from 2014 through 2017 are mainly from a reduction in marketing activity and lower commodity prices. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017.

(b)

Includes the impact of a $78.8 million gain from hurricane insurance proceeds received in 2018, a $43.4 million non-cash loss associated with the sale of our European operations in 2018, a $58.7 million non-cash impairment charge on the term loan to Axeon Specialty Products, LLC in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015. (Loss) income from continuing operations per common unit also includes the impact of a $377.1 million loss as a result of the July 2018 merger with our general partner. Please refer to Notes 4 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.


(c)	The board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the distribution for the first quarter of 2018.


(d)	The significant increases in balance sheet data and income statement data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with “Cautionary Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.

NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented below in seven sections:


•	Overview


•	Results of Operations


•	Trends and Outlook


•	Liquidity and Capital Resources


•	Related Party Transactions


•	Critical Accounting Policies


•	New Accounting Pronouncements

OVERVIEW

Recent Developments

Sale of European Operations. On November 30, 2018, we sold our European operations to Inter Terminals, Ltd. for approximately $270.0 million. The operations sold include six liquids storage terminals in the United Kingdom and one facility in Amsterdam. Prior to the sale, the assets disposed of and the results of operations were included in our storage segment. We recognized a non-cash loss of $43.4 million related to the sale in “Other income (expense), net” on our consolidated statement of income for the year ended December 31, 2018. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Merger Sub merged with and into NuStar GP Holdings, with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy became the sole member of NuStar GP Holdings following the Merger on July 20, 2018. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. We issued approximately 13.4 million incremental NuStar Energy common units as a result of the Merger. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion. On June 29, 2018, we also issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC.

Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-mile pipeline and 18 storage tanks, for approximately $37.5 million (the Council Bluffs Acquisition). The assets acquired and the results of operations are included in our pipeline segment, within the East Pipeline, from the date of acquisition. We accounted for this acquisition as an asset purchase.

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2017, we received insurance proceeds of $12.5 million for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption ($2.4 million recognized in the fuels marketing segment and $1.4 million in the storage segment). In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal, of which $9.1 million related to business interruption ($5.6 million recognized in the storage segment and $3.5 million in the fuels marketing segment). Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. We recorded a $78.8 million gain in “Other income (expense), net” in the consolidated statements of income in the first quarter of 2018 for the amount by which the insurance proceeds exceeded our expenses incurred during the period. Although the repairs are not complete, we expect that the costs to repair the property damage at the terminal will not exceed the amount of insurance proceeds received.

Other Events

Navigator Acquisition. On May 4, 2017, we acquired Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). We collectively refer to the acquired assets, together with the assets we have constructed through various expansion projects since the date of the Navigator Acquisition, as our Permian Crude System. The assets acquired are included in our pipeline segment within the Central West System, commencing on May 4, 2017. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other income (expense), net” in the consolidated statements of income. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus Christi, TX for $95.7 million, including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock. The acquired assets, which are adjacent to our existing Corpus Christi North Beach terminal, increased our storage capacity in the Corpus Christi region and have direct connectivity to Eagle Ford crude oil production.

Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the Fifth Amended and Restated 2000 Long-Term Incentive Plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 4 for further discussion of the Employee Transfer and our related party agreements, Note 23 for a discussion of our employee benefit plans and Note 24 for a discussion of our long-term incentive plans.

Operations

We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”

Storage. We own terminals and storage facilities in the United States, Canada, Mexico and St. Eustatius in the Caribbean Netherlands, with approximately 75.8 million barrels of storage capacity.

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goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The remaining operations in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted accounting principles. In such cases, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility.

Factors That Affect Results of Operations

The following factors affect the results of our operations:


•	company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;


•	seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for products we sell;


•	industry factors, such as changes in the prices of petroleum products that affect demand and the operations of our competitors;


•	economic factors, such as commodity price volatility, that impact our fuels marketing segment; and


•	factors that impact the operations served by our pipeline and storage assets, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers.

Increases or decreases in the price of crude oil affect sectors across the energy industry, including our customers in crude oil production, refining and trading, in different ways at different points in any given price cycle. For example, during periods of sustained low prices, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. Refiners, on the other hand, tend to benefit from lower crude oil prices, to the extent they are able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products; however, as refined product inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude prices. Crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” as is currently the case for certain markets that we serve, traders are no longer incentivized to purchase and store product for future sale.

Current Market Conditions

The price of crude oil began to recover in 2018, as global supply and demand reached a balance. Crude oil prices continued to recover up until the fourth quarter when, after hitting a three-year high in October, prices fell sharply and remained there through year-end. As a result, by year-end 2018, many energy industry experts lowered their crude price expectations for 2019. While crude oil prices have made a modest recovery so far in 2019, they have not returned to the levels previously forecasted. Despite the fact that crude prices are somewhat below many experts’ forecasts, we believe that the lower projected crude prices remain at or above levels that should support healthy crude production growth in the Permian Basin. However, crude oil prices are difficult to predict because they are determined by global supply and demand, which, in turn, are dependent on many variables, such as trade relationships, geopolitical challenges, economic health and relative currency strength.

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RESULTS OF OPERATIONS

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Financial Highlights

(Thousands of Dollars, Except Per Unit Data)



	Year Ended December 31,
	2018			2017			Change
Statement of Income Data:
Revenues:
Service revenues	$	1,206,981		$	1,128,726		$	78,255
Product sales	754,776			685,293			69,483
Total revenues	1,961,757			1,814,019			147,738

Costs and expenses:
Costs associated with service revenues	777,173			705,204			71,969
Cost of product sales	705,946			651,599			54,347
General and administrative expenses	106,200			112,240			(6,040		)
Other depreciation and amortization expense	8,875			8,698			177
Total costs and expenses	1,598,194			1,477,741			120,453

Operating income	363,563			336,278			27,285
Interest expense, net	(186,237		)	(173,083		)	(13,154		)
Other income (expense), net	39,876			(5,294		)	45,170
Income before income tax expense	217,202			157,901			59,301
Income tax expense	11,408			9,937			1,471
Net income	$	205,794		$	147,964		$	57,830
Basic and diluted net (loss) income per common unit	$	(2.77	)	$	0.64		$	(3.41	)

Annual Overview

Net income increased $57.8 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to higher other income, which includes the $78.8 million gain recognized in the first quarter of 2018 from insurance proceeds related to hurricane damage at our St. Eustatius terminal in the third quarter of 2017, partially offset by a $43.4 million loss from the sale of our European operations in the fourth quarter of 2018. Additionally, net income increased from a $21.4 million increase in segment operating income.

Despite positive net income, we incurred a net loss per common unit because we accounted for the Merger as an equity transaction similar to a redemption or induced conversion of preferred stock, which resulted in a loss of $377.1 million that was subtracted from net income attributable to common unitholders in the calculation of net loss per common unit for the year ended December 31, 2018. Please refer to Notes 4 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2018			2017			Change
Pipeline:
Refined products and ammonia pipelines throughput (barrels/day)	557,044			516,736			40,308
Crude oil pipelines throughput (barrels/day)	876,655			583,323			293,332
Total throughput (barrels/day)	1,433,699			1,100,059			333,640
Throughput and other revenues	$	611,065		$	516,288		$	94,777
Operating expenses	184,427			156,432			27,995
Depreciation and amortization expense	153,943			128,061			25,882
Segment operating income	$	272,695		$	231,795		$	40,900

Storage:
Throughput (barrels/day)	341,396			325,194			16,202
Throughput terminal revenues	$	83,157		$	85,927		$	(2,770	)
Storage terminal revenues	522,793			531,026			(8,233		)
Total revenues	605,950			616,953			(11,003		)
Operating expenses	289,423			270,041			19,382
Depreciation and amortization expense	135,056			127,473			7,583
Segment operating income	$	181,471		$	219,439		$	(37,968	)

Fuels Marketing:
Product sales and other revenue	$	752,312		$	692,884		$	59,428
Cost of product sales	713,031			660,844			52,187
Gross margin	39,281			32,040			7,241
Operating expenses	14,841			26,057			(11,216		)
Segment operating income	$	24,440		$	5,983		$	18,457

Consolidation and Intersegment Eliminations:
Revenues	$	(7,570	)	$	(12,106	)	$	4,536
Cost of product sales	(7,085		)	(9,245		)	2,160
Operating expenses	(517		)	(2,860		)	2,343
Total	$	32		$	(1	)	$	33

Consolidated Information:
Revenues	$	1,961,757		$	1,814,019		$	147,738
Costs associated with service revenues:
Operating expenses	488,174			449,670			38,504
Depreciation and amortization expense	288,999			255,534			33,465
Total costs associated with service revenues	777,173			705,204			71,969
Cost of product sales	705,946			651,599			54,347
Segment operating income	478,638			457,216			21,422
General and administrative expenses	106,200			112,240			(6,040		)
Other depreciation and amortization expense	8,875			8,698			177
Consolidated operating income	$	363,563		$	336,278		$	27,285

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Pipeline

Total revenues increased $94.8 million and total throughputs increased 333,640 barrels per day for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to:


•	an increase in revenues of $68.4 million and an increase in throughputs of 242,785 barrels per day resulting from increased customer production supplying our Permian Crude System, completion of pipeline expansion projects and owning and operating the system for the entire period in 2018;


•	an increase in revenues of $16.0 million and an increase in throughputs of 38,624 barrels per day due to a turnaround in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;


•	an increase in revenues of $13.0 million and an increase in throughputs of 11,318 barrels per day on our East Pipeline due to higher diesel throughputs, an increase in long-haul deliveries resulting in higher average tariffs and the Council Bluffs Acquisition; and


•	an increase in revenues of $10.8 million and an increase in throughputs of 8,742 barrels per day, mainly due to a turnaround at the refinery served by our North Pipeline in the second quarter of 2017, as well as turnaround activity at a neighboring refinery in 2018, resulting in higher demand on the North Pipeline.

These increases were partially offset by:


•	a decrease in revenues of $10.8 million on our Eagle Ford System, mainly due to contract renewals at lower rates, which more than offset an increase in throughputs of 47,338 barrels per day; and


•	a decrease in revenues of $3.4 million and a decrease in throughputs of 13,834 barrels per day on our Ardmore System, mainly due to a customer’s refinery turnaround in 2018, as well as an increase in short-haul deliveries, which result in lower average tariffs.

Operating expenses increased $28.0 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, mainly due to:


•	increased operating expenses of $16.5 million as a result of owning the Permian Crude System for the entire period in 2018 and consistent with the increase in throughputs;


•	an increase of $3.1 million resulting from the Council Bluffs Acquisition;


•	an increase of $2.7 million in salaries and wages; and


•	an increase in power expenses of $2.6 million, mainly due to increased throughputs.

Depreciation and amortization expense increased $25.9 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, mainly due to owning the Permian Crude System for the entire period in 2018.

Storage

Throughput terminal revenues decreased $2.8 million, while throughputs increased 16,202 barrels per day for the year ended December 31, 2018, compared to the year ended December 31, 2017. Corpus Christi North Beach terminal revenues decreased by $6.3 million, despite increased throughputs of 10,581 barrels per day mainly driven by higher South Texas Crude System volumes, due to lower storage rates and lower dock revenues as additional volumes were delivered to our customer’s refineries instead of over our docks. Revenues increased $3.8 million and throughputs increased 7,343 barrels per day at our Central West Terminals, mainly due to increased demand in markets served by those terminals.

Storage terminal revenues decreased $8.2 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to:


•	a decrease of $15.5 million at our Gulf Coast Terminals, mainly due to a backwardated market resulting in the non-renewal at expiration of certain customer contracts and lower throughput and associated handling fees;


•	a decrease of $7.1 million at our St. Eustatius terminal, primarily due to renewal of contracts at lower rates, tanks out of service and lower throughput and handling fees;


•	a decrease of $4.4 million due to the sale of our European terminals in the fourth quarter of 2018; and


•	a decrease of $1.9 million due to lower throughput and handling fees at our Point Tupper terminal.

These decreases were partially offset by the following:


•	an increase of $9.4 million at our West Coast Terminals, mainly due to project completions, rate escalations and higher throughput and associated handling fees;

•

an increase of $8.1 million at our North East Terminals, mainly due to an adjustment to revenues resulting from a change in the term of a contract and the completion of a tank expansion project at our Linden terminal, partially offset by a decrease in revenues at our Piney Point terminal due to the non-renewal at expiration of certain customer contracts. Please refer to Note 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the revenue adjustment; and


•	an increase of $1.9 million due to higher reimbursable revenues at our Point Tupper terminal.

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Operating expenses increased $19.4 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to:


•	an increase in salaries and wages of $6.0 million, and an increase in maintenance and regulatory expenses of $2.0 million, both spread across various regions;


•	an increase in reimbursable expenses of $4.9 million at various terminals, primarily due to tank cleanings at our Point Tupper and Corpus Christi North Beach terminals, which was offset by a corresponding increase in reimbursable revenues;


•	an increase in rent expense of $4.4 million, mainly due to additional marine vessel costs at our St. Eustatius terminal;


•	an increase of $1.9 million for contractor services and an increase of $1.8 million in power costs, mainly due to increased dive inspection costs and higher gas consumption, respectively, at our St. Eustatius terminal; and


•	an increase in insurance expense of $1.7 million across all terminals due to premium increases.

These increases were partially offset by a decrease in operating expense of $4.2 million at St. Eustatius due to the business interruption insurance recovery in 2018 versus 2017 related to the hurricane damage.

Depreciation and amortization expense increased $7.6 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, mainly as the result of the completion of various storage projects, primarily at our St. Eustatius terminal.

Fuels Marketing

Segment operating income increased $18.5 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to an increase of $11.2 million in operating income from our blending operations and other product sales, and a reduction in operating losses of $5.6 million incurred by our heavy fuels trading operations.

Consolidation and Intersegment Eliminations

Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General

General and administrative expenses decreased $6.0 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to transaction costs related to the Navigator Acquisition in 2017, partially offset by higher compensation costs.

Interest expense, net increased $13.2 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, mainly due to the issuance of $550.0 million of 5.625% senior notes on April 28, 2017 to partially fund the Navigator Acquisition and higher interest rates.

For the year ended December 31, 2018, we recorded other income, net of $39.9 million, primarily due to a $78.8 million gain recognized in the first quarter from insurance proceeds related to hurricane damage at our St. Eustatius terminal in the third quarter of 2017, partially offset by a $43.4 million loss on the sale of our European operations in the fourth quarter of 2018. For the year ended December 31, 2017, we recorded other expense, net of $5.3 million, mainly due to a $5.0 million loss for property damage at our St. Eustatius terminal resulting from the hurricane activity in the third quarter of 2017.

Income tax expense increased $1.5 million for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to an increase in taxes associated with the Permian Crude System and higher foreign withholding taxes.

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Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Financial Highlights

(Thousands of Dollars, Except Per Unit Data)



	Year Ended December 31,
	2017			2016			Change
Statement of Income Data:
Revenues:
Service revenues	$	1,128,726		$	1,083,165		$	45,561
Product sales	685,293			673,517			11,776
Total revenues	1,814,019			1,756,682			57,337

Costs and expenses:
Costs associated with service revenues	705,204			656,584			48,620
Cost of product sales	651,599			633,653			17,946
General and administrative expenses	112,240			98,817			13,423
Other depreciation and amortization expense	8,698			8,519			179
Total costs and expenses	1,477,741			1,397,573			80,168

Operating income	336,278			359,109			(22,831		)
Interest expense, net	(173,083		)	(138,350		)	(34,733		)
Other expense, net	(5,294		)	(58,783		)	53,489
Income before income tax expense	157,901			161,976			(4,075		)
Income tax expense	9,937			11,973			(2,036		)
Net income	$	147,964		$	150,003		$	(2,039	)
Basic and diluted net income per common unit:	$	0.64		$	1.27		$	(0.63	)

Annual Overview

Net income slightly decreased for the year ended December 31, 2017, compared to the year ended December 31, 2016. The decrease in other expense, net, mainly resulting from a $58.7 million impairment charge on the Axeon Term Loan in 2016, was offset by increased interest expense, increased general and administrative expenses and decreased segment operating income.

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2017			2016			Change
Pipeline:
Refined products and ammonia pipelines throughput (barrels/day)	516,736			535,946			(19,210		)
Crude oil pipelines throughput (barrels/day)	583,323			392,181			191,142
Total throughput (barrels/day)	1,100,059			928,127			171,932
Throughput revenues	$	516,288		$	485,650		$	30,638
Operating expenses	156,432			147,858			8,574
Depreciation and amortization expense	128,061			89,554			38,507
Segment operating income	$	231,795		$	248,238		$	(16,443	)

Storage:
Throughput (barrels/day)	325,194			789,065			(463,871		)
Throughput terminal revenues	$	85,927		$	117,586		$	(31,659	)
Storage terminal revenues	531,026			492,456			38,570
Total revenues	616,953			610,042			6,911
Operating expenses	270,041			276,578			(6,537		)
Depreciation and amortization expense	127,473			118,663			8,810
Segment operating income	$	219,439		$	214,801		$	4,638

Fuels Marketing:
Product sales and other revenue	$	692,884		$	681,934		$	10,950
Cost of product sales	660,844			645,355			15,489
Gross margin	32,040			36,579			(4,539		)
Operating expenses	26,057			33,173			(7,116		)
Segment operating income	$	5,983		$	3,406		$	2,577

Consolidation and Intersegment Eliminations:
Revenues	$	(12,106	)	$	(20,944	)	$	8,838
Cost of product sales	(9,245		)	(11,702		)	2,457
Operating expenses	(2,860		)	(9,242		)	6,382
Total	$	(1	)	$	—		$	(1	)

Consolidated Information:
Revenues	$	1,814,019		$	1,756,682		$	57,337
Costs associated with service revenues:
Operating expenses	449,670			448,367			1,303
Depreciation and amortization expense	255,534			208,217			47,317
Total costs associated with service revenues	705,204			656,584			48,620
Cost of product sales	651,599			633,653			17,946
Segment operating income	457,216			466,445			(9,229		)
General and administrative expenses	112,240			98,817			13,423
Other depreciation and amortization expense	8,698			8,519			179
Consolidated operating income	$	336,278		$	359,109		$	(22,831	)

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Pipeline

Total revenues increased $30.6 million and total throughputs increased 171,932 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:


•	an increase in revenues of $42.6 million and an increase in throughputs of 192,958 barrels per day from our Permian Crude System acquired in May 2017;


•	an increase in revenues of $5.5 million and an increase in throughputs of 2,929 barrels per day due to maintenance downtime in 2016 on a portion of the Ammonia Pipeline, as well as operational issues in 2016 at certain plants served by the pipeline; and

•

an increase in revenues of $3.4 million, despite a decrease in throughputs of 4,129 barrels per day, on our East Pipeline due to the completion of various storage projects along the pipeline, as well as an increase in long-haul deliveries resulting in higher average tariffs. A turnaround and operational issues at the refineries served by the East Pipeline in 2017 contributed to the decrease in throughputs.

These increases in revenues and throughputs were partially offset by:


•	a decrease in revenues of $10.4 million and a decrease in throughputs of 16,839 barrels per day due to a turnaround in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;


•	a decrease in revenues of $6.8 million and a decrease in throughputs of 15,561 barrels per day on our Eagle Ford System, mainly due to reduced production in a sustained low crude oil price environment; and


•	a decrease in revenues of $4.8 million and a decrease in throughputs of 6,905 barrels per day due to a turnaround in the second quarter of 2017 at the refinery served by the North Pipeline.

Operating expenses increased $8.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016. Operating expenses increased $9.9 million as a result of our acquisition of the Permian Crude System, which was partially offset by a decrease of $2.1 million from product imbalances on the East Pipeline.

Depreciation and amortization expense increased $38.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to our acquisition of the Permian Crude System and the completion of various pipeline projects.

Storage

Effective January 1, 2017, our agreements for our refinery crude storage tanks at Corpus Christi, TX, Texas City, TX and Benicia, CA were amended to change our fees from throughput-based to storage-based. Excluding the effect of the change to these agreements, throughput terminal revenues would have increased $9.5 million and throughputs would have increased 14,360 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016. Throughput terminal revenues increased at our Corpus Christi North Beach terminal by $15.1 million due to an increase in throughputs of 26,359 barrels per day, mainly resulting from the Martin Terminal Acquisition. The benefit of the Martin Terminal Acquisition was partially offset by lower revenues and throughputs resulting from a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi due to reduced production in a sustained low crude oil price environment. Throughputs increased 16,309 barrels per day, despite only a slight increase in revenues of $0.3 million, at our Central West Terminals, mainly due to a new customer contract and increased marine activity, mostly offset by decreased revenues from ancillary services. These increases in revenues and throughputs were partially offset by decreased revenues of $5.8 million and decreased throughputs of 28,308 barrels per day at our Paulsboro, NJ terminal as a customer diverted barrels to other terminals.

Storage terminal revenues would have decreased $0.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, excluding the effect of the change to the refinery storage tank agreements described above. Revenues at our Gulf Coast Terminals decreased $19.2 million, mainly at our St. James, LA terminal due to reduced unit train activity and at our Texas City, TX terminal as a result of the exit from our heavy fuels trading operations. These decreases were partially offset by increases in revenues of $8.2 million at our North East Terminals and $4.5 million at our West Coast Terminals, mainly due to new customer contracts and rate escalations.

Storage terminal revenues also increased $5.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, at our international terminals. Revenues increased $10.2 million at our St. Eustatius terminal, mainly due to new customer contracts and rate escalations, partially offset by lower throughput and associated handling fees as a result of the temporary shutdown of the terminal and damage caused by hurricane activity in the third quarter of 2017. This increase was partially offset by a decrease in revenues of $4.2 million at our Point Tupper terminal, mainly resulting from a decrease in customer base, tanks out of service and lower reimbursable revenues.

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Operating expenses decreased $6.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:


•	a decrease of $8.7 million in maintenance and regulatory expenses, primarily at our St. Eustatius, North East and Point Tupper terminals; and


•	a decrease of $6.1 million in reimbursable expenses, mainly at our Texas City, TX and Point Tupper terminals, consistent with the decrease in reimbursable revenues.

These decreases were partially offset by increased operating expenses of $8.5 million as a result of the Martin Terminal Acquisition.

Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to the Martin Terminal Acquisition and other various projects.

Fuels Marketing

Segment operating income increased $2.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to a reduction in losses of $9.1 million from exiting our heavy fuels trading operations in 2017. Segment operating income from our bunker fuel operations at our St. Eustatius terminal decreased $6.4 million, due to lower gross margins and the temporary shutdown of the terminal caused by hurricane activity in the third quarter of 2017.

Consolidation and Intersegment Eliminations

General

General and administrative expenses increased $13.4 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to transaction costs related to the Navigator Acquisition.

Interest expense, net increased $34.7 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, mainly due to the issuance of $550.0 million of 5.625% senior notes in April 2017 and as a result of fees for a bridge loan commitment to potentially assist with the financing of the Navigator Acquisition. We did not enter into or borrow under the bridge loan. Interest expense, net also increased as a result of lower interest income due to the termination of the Axeon Term Loan in February 2017. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the Axeon Term Loan and related credit support.

For the year ended December 31, 2017, we recorded other expense, net of $5.3 million, mainly due to property damage of $5.0 million at our St. Eustatius terminal resulting from hurricane activity in the third quarter of 2017. For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan.

Income tax expense decreased $2.0 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to reductions in withholding taxes related to certain of our foreign subsidiaries. This decrease was partially offset by increased tax expense resulting from the enactment of the Tax Cuts and Jobs Act in December 2017 (the Act), pursuant to which we recorded a one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries. Please refer to Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes, including the impact of the Act.

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TRENDS AND OUTLOOK

In early 2018, we launched a comprehensive plan to achieve the characteristics now demanded by the master limited partnership market: simplified corporate governance with no incentive distribution rights, minimal equity capital needs, lower leverage and strong distribution coverage. Over the course of the year, we executed our plan by, among other things, selling our European operations, which reduced our debt; completing the merger with our general partner, which both simplified our structure and resulted in the cancellation of the incentive distribution rights previously held by our general partner; resetting our quarterly distribution; and issuing our Series D Preferred Units. With lower leverage metrics and higher distribution coverage, we have positioned ourselves to fund a larger proportion of our capital projects with the cash generated by our operations, thus reducing our need to access common equity markets to finance future growth opportunities.

The majority of significant growth opportunities for midstream crude oil pipeline companies today emanate from the growth in Permian Basin production, and we expect to benefit from that growth within our Permian System and at other assets experiencing a “spillover” effect from Permian Basin growth. In 2019, we expect to continue to expand our Permian System to capture higher throughputs and revenues. Outside the Permian Basin, but related to its growth, we expect our existing crude oil pipelines, including our Wichita Falls, Ardmore and South Texas crude systems, to benefit in 2019 from our customers’ long-haul opportunities to transport Permian crude. Our Wichita Falls and Ardmore pipelines should benefit from higher revenues as we complete connections of those pipelines to Permian production sources. Also, revenues on our South Texas Crude System should increase as we complete the construction of a project to connect a portion of that system with new pipelines carrying Permian production bound for export. That project is backed by a customer commitment and is expected to be in service in the second half of 2019. We also expect our storage facilities in Corpus Christi, Texas and St. James, Louisiana to benefit in 2019 as pipeline projects to move Permian production come online. Longer term, as Permian Basin production continues to grow and exceeds the demand from domestic refiners, we expect those incremental volumes to be exported, most likely from Gulf Coast facilities. We believe our Gulf Coast storage facilities are well positioned to benefit from those export opportunities.

In addition to the Permian-related growth, we also expect 2019 results to benefit from a pipeline expansion project to facilitate the export of refined products to Northern Mexico and the completion of a number of bio-fuel projects at our West Coast terminals in 2018 and 2019.

While backwardated crude prices in 2019 could have a detrimental impact on some of our storage facilities, we believe we are insulated to some extent by our long-term contracts at certain of our facilities where backwardation is a driving factor, and due to the fact that we have storage assets in markets in which forward pricing has little impact on rates or renewals.

The severe political, social and economic instability in Venezuela in recent years, as well as the sanctions implemented in 2017 by the United States and others, have had a negative impact on the ability of Petroleos de Venezuela, S.A. (PDVSA), a customer at our St. Eustatius facility, to conduct its operations and to pay its creditors timely. On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC) added PDVSA to its List of Specially Designated Nationals and Blocked Persons (the SDN List). The inclusion of PDVSA on the SDN List prevents us from providing services to PDVSA until such time as these sanctions are lifted or otherwise modified. Since January 28, we have taken all necessary steps to wind down our contracts with PDVSA, in accordance with the requirements of applicable laws, and we are now in the process of marketing the storage capacity no longer leased to PDVSA to other customers. We expect to replace their full position over the next 18 months.

Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned refinery downtime, crude oil prices, the supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our transportation and storage services and changes in laws or regulations affecting our assets.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Our primary cash requirements are for distributions to our partners, debt service, capital expenditures, acquisitions and operating expenses.

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and, prior to the Merger, to our general partner each quarter. “Available Cash” is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors, subject to requirements for distributions for our preferred units. The board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the 2018 first-quarter distribution, which was paid on May 14, 2018. As a result of the Merger, our general partner no longer receives incentive distributions or quarterly cash distributions from us, and we issued approximately 13.4 million incremental NuStar Energy common units in exchange for previously outstanding NSH units. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion regarding the Merger.

Each year, our objective is to fund our reliability capital expenditures and distribution requirements with our net cash provided by operating activities during that year. If we do not generate sufficient cash from operations to meet that objective, we utilize cash on hand or other sources of cash flow, which in the past have primarily included borrowings under our revolving credit agreement, sales of non-strategic assets and, to the extent necessary, funds raised through equity or debt offerings. We have typically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the availability thereof.

During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may maintain our distribution level because we can use other sources of Available Cash, as provided in our partnership agreement, including borrowings under our revolving credit agreement and proceeds from the sales of assets. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent in our ability to maintain or grow our distribution.

For 2019, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements.

Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

The following table summarizes our cash flows from operating, investing and financing activities (please refer to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”):



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	544,207		$	406,799		$	436,761
Investing activities	(153,778		)	(1,696,441		)	(311,078		)
Financing activities	(399,867		)	1,276,272			(211,324		)
Effect of foreign exchange rate changes on cash	(1,210		)	1,720			2,721
Net decrease in cash and cash equivalents	$	(10,648	)	$	(11,650	)	$	(82,920	)

Net cash provided by operating activities for the year ended December 31, 2018 was $544.2 million, compared to $406.8 million for the year ended December 31, 2017, primarily due to changes in working capital. Our working capital decreased by $78.3 million for the year ended December 31, 2018, compared to an increase of $26.5 million for the year ended December 31, 2017. Please refer to the “Working Capital Requirements” section below for a discussion of the changes in working capital.

For the year ended December 31, 2018, net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $391.4 million and the cash consideration for the Merger of $67.8 million. Net cash provided by operating activities and a portion of the insurance proceeds we received in the first quarter of 2018 in settlement of our property damage claim for our St. Eustatius terminal were used to fund reliability capital expenditures of $77.2 million. The remainder of cash provided by operating activities and proceeds from debt borrowings were used to fund our strategic capital expenditures, including acquisitions, of $417.8 million. The proceeds from the issuance of

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units and the sale of our European operations and a portion of the insurance proceeds were used to repay outstanding borrowings under our revolving credit agreement.

For the year ended December 31, 2017, net cash provided by operating activities, the proceeds from the termination of the Axeon Term Loan of $110.0 million and cash on hand were used to fund our distributions to unitholders and our general partner in the aggregate amount of $485.1 million and reliability capital expenditures of $57.5 million. Proceeds from our debt and equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund our other strategic capital expenditures.

For the year ended December 31, 2016, net cash provided by operating activities primarily was used to fund our distributions to unitholders and our general partner in the aggregate amount of $393.0 million and reliability capital expenditures of $38.2 million. Proceeds from the issuance of common and preferred units and cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.

Debt Sources of Liquidity

Revolving Credit Agreement. On June 29, 2018, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement) to exclude the Series D Preferred Units from the definition of “Indebtedness.” Additionally, the amendment reduced the total amount available for borrowing from $1.75 billion to $1.575 billion, effective June 29, 2018, with a further reduction to $1.4 billion, effective December 28, 2018. The Revolving Credit Agreement was also amended to, among other things, add a minimum consolidated interest coverage ratio (as defined in the Revolving Credit Agreement), which must not be less than 1.75-to-1.00 for each rolling period of four quarters, beginning with the rolling period ending June 30, 2018. As of December 31, 2018, our consolidated interest coverage ratio was 2.2x.

On March 28, 2018, NuStar Logistics amended the Revolving Credit Agreement to increase the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) to 5.25-to-1.00 for the rolling periods ending June 30, 2018 through December 31, 2018. For any rolling periods ending on or after March 31, 2019, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00. The Revolving Credit Agreement was also amended to, among other things, provide that the definition of “Change in Control” in the Revolving Credit Agreement excludes the Merger.

The maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. As of December 31, 2018, our consolidated debt coverage ratio was 4.05x and we had $651.3 million available for borrowing. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

Letters of credit issued under the Revolving Credit Agreement totaled $3.7 million as of December 31, 2018. Letters of credit are limited to $400.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.

Receivables Financing Agreement. NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables Financing Agreement, the Securitization Program). On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. On March 28, 2018, the Receivables Financing Agreement was amended to change the definition of Change in Control in the Receivables Financing Agreement such that the Merger would not be a Change in Control for purposes of the Receivables Financing Agreement. The amount of borrowings under the Receivables Financing Agreement is limited to $125.0 million. The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.

Issuance of 5.625% Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the

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Navigator Acquisition and to pay related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017. The 5.625% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. The 5.625% senior notes contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales.

Other Debt Sources of Liquidity. Other sources of liquidity as of December 31, 2018 consist of the following:


•	$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone Act of 2005 (the GoZone Bonds), with $42.9 million remaining in trust as of December 31, 2018, supported by $370.2 million in letters of credit; and


•	one short-term line of credit agreement with an uncommitted borrowing capacity of up to $35.0 million, with $18.5 million of borrowings outstanding as of December 31, 2018.

Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

LOC Agreement

NuStar Logistics is a party to a $100.0 million uncommitted letter of credit agreement, which provides for standby letters of credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do not reduce availability under the Revolving Credit Agreement. As of December 31, 2018, we had no letters of credit issued under the LOC Agreement.

Repatriation

We may repatriate a portion of undistributed foreign earnings in order to provide greater flexibility to meet cash flow needs. During the year ended December 31, 2017, we repatriated $9.5 million of cash from our foreign subsidiaries. We will continue to evaluate our cash flow needs and may repatriate funds from our foreign subsidiaries as a source of liquidity.

Issuances of Units

Series D Preferred Units. On June 29, 2018, we issued 15,760,441 Series D Preferred Units at a price of $25.38 per unit in a private placement for net proceeds of $370.7 million. On July 13, 2018, we issued an additional 7,486,209 Series D Preferred Units at a price of $25.38 per unit in a private placement for net proceeds of $185.1 million. The Series D Preferred Units contain various conversion and redemption features. In connection with the issuance, we also entered into a Registration Rights Agreement with the purchasers of the Series D Preferred Units relating to the registration of the Series D Preferred Units and the common units issuable upon conversion of the Series D Preferred Units.

Series C Preferred Units. In the fourth quarter of 2017, we issued 6,900,000 of our 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series C Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $166.7 million from the issuance of the Series C Preferred Units for general partnership purposes, including the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.

Series B Preferred Units. In the second quarter of 2017, we issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $371.8 million from the issuance of the Series B Preferred Units to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses.

Series A Preferred Units. In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.

Common Units. As a result of the Merger, in the third quarter of 2018, we issued approximately 13.4 million incremental NuStar Energy common units in exchange for the previously outstanding NSH units.

In the second quarter of 2018, we issued 413,736 common units at a price of $24.17 per unit for total proceeds of $10.2 million, including a contribution of $0.2 million from our general partner to maintain the 2% general partner economic interest it owned at that time.

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In the second quarter of 2017, we issued 14,375,000 common units at a price of $46.35 per unit. We used the net proceeds from this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain the 2% general partner economic interest it owned at that time, to fund a portion of the purchase price for the Navigator Acquisition. Beginning with the distribution earned for the second quarter of 2017, our general partner did not receive incentive distributions with respect to these common units. Our general partner amended and restated our partnership agreement to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Navigator Acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan).

In the third quarter of 2016, we issued 595,050 common units at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds, which include a contribution of $0.6 million from our general partner to maintain the 2% general partner economic interest it owned at that time, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.

Please see Notes 19 and 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on these issuances.

Capital Requirements

Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:


•	strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions; and


•	reliability capital expenditures, such as those required to maintain the current operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety.

The following table summarizes our capital expenditures for the past three years, and the amount we expect to spend in 2019:



	Strategic
	Acquisitions		Capital Expenditures		Reliability Capital Expenditures		Total
	(Thousands of Dollars)
For the year ended December 31:
2018	$	37,502	$	380,298	$	77,154	$	494,954
2017	$	1,461,719	$	327,141	$	57,497	$	1,846,357
2016	$	95,657	$	166,203	$	38,155	$	300,015

Expected for the year ended December 31, 2019			$ 500,000 - 550,000		$ 70,000 - 90,000

Other strategic capital expenditures for 2018 mainly consisted of pipeline expansions on our Permian Crude System, projects at our St. Eustatius terminal and a terminal expansion project at our Linden terminal, while other strategic capital expenditures for 2016 and 2017 mainly consisted of terminal expansions. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals, including costs to repair the property damage at our St. Eustatius terminal facility, which totaled $34.7 million in 2018.

For the year ended December 31, 2019, we expect a significant portion of our strategic capital spending to relate to our Permian Crude System, Northern Mexico refined products supply projects and an export project to connect our Corpus Christi North Beach terminal to long-haul pipelines transporting crude oil from the Permian Basin. We expect a significant portion of reliability capital spending to relate to hurricane damage repairs at our St. Eustatius terminal facility, which includes approximately $35.0 million that will be funded with insurance proceeds already received, and completion of our Ammonia Pipeline replacement project. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2019 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with the sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2019, and our internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.

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Working Capital Requirements

Working capital requirements are mainly affected by our accounts receivable and accounts payable balances, which vary depending on the timing of payments. Our accounts receivable and accounts payable balances related to our bunkering operations were affected by the temporary shutdown of our St. Eustatius terminal in September of 2017. Changes in our accounts receivable, accounts payable and inventory balances were also affected by our exit from our heavy fuels trading and crude oil marketing operations in 2017.

During the year ended December 31, 2018, accrued liabilities increased $39.6 million, mainly due to the recognition of a contract liability associated with a non-refundable one-time payment of storage fees from a customer. Please refer to Note 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information. Additionally, accounts receivable decreased $22.5 million, mainly due to the sale of our European operations in the fourth quarter of 2018.

During the year ended December 31, 2017, accounts payable decreased $30.4 million and inventories decreased $11.9 million, primarily due to our exit from our heavy fuels trading and crude oil marketing operations in 2017.

During the year ended December 31, 2016, accounts receivable increased $23.2 million and accounts payable increased $14.1 million, primarily due to the timing of payments related to our bunker fuel operations and crude oil trading activity.

Axeon Term Loan and Credit Support

On February 22, 2017, we settled and terminated the $190.0 million Axeon Term Loan, pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon. We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other income (expense), net” in the consolidated statements of income. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Defined Benefit Plans Funding

During 2018, we contributed $11.2 million to our pension and postretirement benefit plans. We expect to contribute approximately $11.6 million to our pension and postretirement benefit plans in 2019, which principally represents contributions

either required by regulations or laws or, with respect to unfunded plans, necessary to fund current benefits. Pension and postretirement benefit plans funding beyond 2019 is uncertain as the funding varies from year to year based upon changes in the fair value of the plan assets and actuarial assumptions.

Distributions

General Partner and Common Limited Partners. Pursuant to the terms of our partnership agreement, prior to the Merger, the general partner received a 2% distribution with respect to its general partner economic interest it owned at that time. The general partner was also entitled to incentive distributions if the amount we distributed with respect to any quarter exceeded $0.60 per unit. For the first quarter of 2018, the general partner did not receive incentive distributions because the distribution declared was $0.60 per common unit, which was below the amount necessary to receive incentive distributions. Because the Merger was effective prior to the record date for the distribution for the second quarter of 2018, the general partner received no distributions after the first quarter distribution. Beginning with the second quarter of 2018, the common limited partners’ distribution includes the additional common units issued in exchange for previously outstanding NSH units because the Merger closed prior to the common unit distribution record date for the second quarter of 2018. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger. For a discussion of the incentive distribution targets prior to the Merger, please read Note 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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The following table reflects the allocation of total cash distributions to the general partner and common limited partners applicable to the period in which the distributions were earned:



	Year Ended December 31,
	2018		2017		2016
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	1,141	$	9,252	$	7,877
General partner incentive distribution	—		45,669		43,407
Total general partner distribution	1,141		54,921		51,284
Common limited partners’ distribution	248,705		407,681		342,598
Total cash distributions	$	249,846	$	462,602	$	393,882

Cash distributions per unit applicable to common limited partners	$	2.40	$	4.38	$	4.38

Distribution payments are made to our common limited partners and, prior to the Merger, were made to our general partner, within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information about quarterly cash distributions to our common limited partners and, prior to the Merger, our general partner:



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 31, 2018	$	0.60	$	64,336	February 8, 2019	February 13, 2019
September 30, 2018	$	0.60	$	64,248	November 8, 2018	November 14, 2018
June 30, 2018	$	0.60	$	64,205	August 7, 2018	August 13, 2018
March 31, 2018	$	0.60	$	57,057	May 8, 2018	May 14, 2018

Preferred Units. The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units:



Units	Fixed Distribution Rate Per Annum (as a Percentage of the $25.00 Liquidation Preference Per Unit)	Fixed Distribution Rate Per Unit Per Annum		Fixed Distribution Per Annum		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference Per Unit)
				(Thousands of Dollars)
Series A Preferred Units	8.50%	$	2.125	$	19,253	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	7.625%	$	1.90625	$	29,357	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	9.00%	$	2.25	$	15,525	December 15, 2022	Three-month LIBOR plus 6.88%

As discussed above, in June and July of 2018, we issued an aggregate of 23,246,650 Series D Preferred Units. The distribution rate on the Series D Preferred Units is: (i) 9.75% per annum ($57.6 million) for the first two years; (ii) 10.75% per annum ($63.4 million) for years three through five; and (iii) the greater of 13.75% per annum ($81.1 million) or the distribution per common unit thereafter. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. For the four distribution periods beginning with the initial Series D Preferred Unit distribution, the Series D Preferred Unit distributions may be paid, in the Partnership’s sole discretion, in (i) cash or (ii) a combination of additional Series D Preferred Units and cash, provided that up to 50% of the distribution amount may be paid in additional Series D Preferred Units. Thereafter, any Series D Preferred Unit distributions in excess of $0.635 may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash. If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the

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applicable distribution rate for those distribution periods shall be increased by $0.048 per Series D Preferred Unit. We would also be subject to other requirements.

Distributions on our preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. Please see Notes 19 and 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Debt Obligations

As of December 31, 2018, we were a party to the following debt agreements:


•	Revolving Credit Agreement due October 29, 2020, with $745.0 million of borrowings outstanding as of December 31, 2018;

•

4.80% senior notes due September 1, 2020 with a face value of $450.0 million; 6.75% senior notes due February 1, 2021 with a face value of $300.0 million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; 5.625% senior notes due April 28, 2027 with a face value of $550.0 million; and subordinated notes due January 15, 2043 with a face value of $402.5 million and a floating interest rate;


•	$365.4 million in GoZone Bonds due from 2038 to 2041;


•	Line of credit agreement with $18.5 million of borrowings outstanding as of December 31, 2018; and


•	Receivables Financing Agreement due September 20, 2020, with $61.8 million of borrowings outstanding as of December 31, 2018.

We repaid our $350.0 million of 7.65% senior notes due April 15, 2018 with borrowings under our Revolving Credit Agreement.

Effective January 15, 2018, the interest rate on NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes due January 15, 2043 switched from a fixed annual rate of 7.625%, payable quarterly in arrears, to an annual rate equal to the sum of the three-month LIBOR for the related quarterly interest period, plus 6.734% payable quarterly, commencing with the interest payment due April 15, 2018. As of December 31, 2018, the interest rate was 9.2%.

Management believes that, as of December 31, 2018, we are in compliance with the ratios and covenants contained in our debt instruments. A default under certain of our debt agreements would be considered an event of default under other of our debt instruments. Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

Credit Ratings

The following table reflects the current outlook and ratings that have been assigned to our debt as of December 31, 2018:



	S&P Global Ratings	Moody’s Investor Service Inc.	Fitch, Inc.
Ratings	BB	Ba2	BB
Outlook	Negative	Negative	Negative

The interest rate payable on the $350.0 million of 7.65% senior notes due 2018 (the 7.65% Senior Notes) was (prior to its repayment in April 2018), and the interest rate payable on the Revolving Credit Agreement is, subject to adjustment if our credit rating is downgraded (or upgraded) by certain credit rating agencies. In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2, which caused the interest rate on the 7.65% Senior Notes to increase by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018. This Moody’s downgrade also caused the interest rate on our Revolving Credit Agreement to increase by 0.25%. In March 2018, Fitch, Inc. changed our outlook from stable to negative, which did not impact interest rates on the 7.65% Senior Notes or the Revolving Credit Agreement.

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Interest Rate Swaps

As of December 31, 2018 and 2017, we were a party to forward-starting interest rate swap agreements for the purpose of hedging interest rate risk. As of December 31, 2018 and 2017, the aggregate notional amount of these forward-starting interest rate swaps was $250.0 million and $600.0 million, respectively. In connection with the April 2018 maturity of the 7.65% Senior Notes, we terminated forward-starting interest rate swap agreements with an aggregate notional amount of $350.0 million and received $8.0 million. Please refer to Notes 2 and 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for a more detailed discussion of our interest rate swaps.

Long-Term Contractual Obligations

The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, 2018:



	Payments Due by Period
	2019		2020		2021		2022		2023		Thereafter		Total
	(Thousands of Dollars)
Long-term debt maturities	$	—	$	1,256,800	$	300,000	$	250,000	$	—	$	1,317,940	$	3,124,740
Interest payments (a)	173,827		168,148		104,870		88,616		83,303		1,118,699		1,737,463
Operating leases (b)	34,900		20,787		14,904		9,280		6,870		28,552		115,293
Purchase obligations (c)	10,896		7,958		7,011		4,970		602		2,624		34,061
Total	$	219,623	$	1,453,693	$	426,785	$	352,866	$	90,775	$	2,467,815	$	5,011,557


(a)	The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as of December 31, 2018. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2018.


(b)	Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius facility and land and dock leases at various terminal facilities, including a build-to-suit lease with an initial term of five years and four additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes.


(c)	A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transaction.

We also have pension and other postretirement benefit obligations recorded in “Other long-term liabilities” on our consolidated balance sheets which have been excluded from the contractual obligations table above due to the uncertainty in timing as to the future cash flows related to these obligations. For additional information on our pension and other postretirement benefit obligations see Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

Environmental, Health and Safety

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2018 and 2017 are included in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.

Contingencies

We are subject to certain loss contingencies, and we believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would not have a material adverse effect on our results of operations, financial position or liquidity, as further disclosed in Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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RELATED PARTY TRANSACTIONS

In conjunction with the Merger, which closed on July 20, 2018, we terminated the Amended and Restated Services Agreement with NuStar GP, LLC. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our related party agreements prior to the Merger.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting policies below are considered critical due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” which summarizes our significant accounting policies.

Depreciation

We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 5 years to 40 years. Changes in the estimated useful lives of our property, plant and equipment could have a material adverse effect on our results of operations.

Impairment of Long-Lived Assets

We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.

In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions as to:


•	whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be recoverable;


•	the grouping of assets;


•	the intention of holding, abandoning or selling an asset;


•	the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and


•	if an impairment exists, the fair value of the asset or asset group.

Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could cause a different conclusion about the recoverability of our assets. If that were to occur, and we determined an asset was impaired, the amount of impairment could be material to our results of operations.

Impairment of Goodwill

We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial performance, other entity-specific events and events affecting individual reporting units. If after assessing the totality of events or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair value, then we would perform an impairment test for that reporting unit. However, we chose to perform a quantitative goodwill impairment test for all reporting units as of October 1, 2018.

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growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential.

We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities.

Our reporting units to which goodwill has been allocated consist of the following:


•	crude oil pipelines;


•	refined product pipelines;


•	terminals, excluding our St. Eustatius and Point Tupper facilities and our refinery crude storage tanks; and


•	bunkering activity at our St. Eustatius and Point Tupper facilities.

Although we determined that no impairment charges resulted from our October 1, 2018 impairment assessment, the fair value of the reporting unit that conducts bunkering activity at our St. Eustatius and Point Tupper facilities (the Statia Bunkering Reporting Unit) exceeded its carrying value by approximately 2%. The goodwill associated with the Statia Bunkering Reporting Unit totaled $31.1 million as of December 31, 2018. Our estimate of the fair value of the Statia Bunkering Reporting Unit is sensitive to typical valuation assumptions, particularly future earnings and cash flows. Recently, the earnings of our Statia Bunkering Reporting Unit have declined compared to historical norms, mostly due to the continued impact from hurricanes that damaged much of the infrastructure in the Caribbean. Our estimates assume the earnings of the Statia Bunkering Reporting Unit return to those historical levels in the near term. However, if there is a prolonged reduction in our earnings from the lingering effect described above, or other factors that result in a slower than anticipated recovery in our earnings, it could result in a reduction of our estimated fair value of the Statia Bunkering Reporting Unit to an amount less than its carrying value. We will continue to monitor the business and consider additional interim analysis of goodwill as appropriate.

Derivative Financial Instruments

We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. We record derivative instruments in the consolidated balance sheets at fair value, and apply hedge accounting when appropriate. We record changes to the fair values of derivative instruments in earnings for fair value hedges or as part of accumulated other comprehensive income (AOCI) for the effective portion of cash flow hedges. We reclassify the effective portion of cash flow hedges from AOCI to earnings when the underlying forecasted transaction occurs or becomes probable not to occur. We recognize ineffectiveness resulting from our derivatives immediately in earnings. With respect to cash flow hedges, we must exercise judgment to assess the probability of the forecasted transaction, which, among other things, depends upon market factors and our ability to reliably operate our assets.

Defined Benefit Plans

We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by Moody’s Investor Service Inc., S&P Global Ratings and Fitch, Inc. The expected long-term rate of return on plan assets is based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of compensation increase represents average long-term salary increases.

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These assumptions can have an effect on the amounts reported in our consolidated financial statements. A 0.25% change in the specified assumptions would have the following effects (thousands of dollars):



	Pension Benefits		Other Postretirement Benefits
Increase in benefit obligation as of December 31, 2018 from:
Discount rate decrease	$	4,800	$	400
Compensation rate increase	$	1,500	n/a
Increase in net periodic benefit cost for the year ending December 31, 2019 resulting from:
Discount rate decrease	$	300	$	100
Expected long-term rate of returns on plan assets decrease	$	300	n/a
Compensation rate increase	$	400	n/a

Please refer to Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of our pension and other postretirement benefit obligations.

Environmental Liabilities

Environmental remediation costs are expensed and an associated accrual is established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have adequately accrued for our environmental exposures.

Contingencies

We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made.

NEW ACCOUNTING PRONOUNCEMENTS

Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of new accounting pronouncements.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. Borrowings under our variable-rate debt expose us to increases in interest rates.

In connection with the April 2018 maturity of the 7.65% Senior Notes, we terminated forward-starting interest rate swap agreements with an aggregate notional amount of $350.0 million and received $8.0 million.

Please refer to Notes 2 and 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our interest rate swaps. The following tables present principal cash flows and related weighted-average interest rates by expected maturity dates for our long-term debt:



	December 31, 2018
	Expected Maturity Dates
	2019		2020			2021			2022			2023		There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate	$	—	$	450,000		$	300,000		$	250,000		$	—	$	550,000		$	1,550,000		$	1,499,920
Weighted-average rate	—		4.8		%	6.8		%	4.8		%	—		5.6		%	5.5		%	—
Variable-rate	$	—	$	806,800		$	—		$	—		$	—	$	767,940		$	1,574,740		$	1,556,784
Weighted-average rate	—		4.4		%	—			—			—		5.6		%	5.0		%	—



	December 31, 2017
	Expected Maturity Dates
	2018			2019		2020			2021			2022			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate	$	350,000		$	—	$	450,000		$	300,000		$	250,000		$	952,500		$	2,302,500		$	2,355,535
Weighted-average rate	8.4		%	—		4.8		%	6.8		%	4.8		%	6.5		%	6.3		%	—
Variable-rate	$	—		$	—	$	955,611		$	—		$	—		$	365,440		$	1,321,051		$	1,322,087
Weighted-average rate	—			—		3.1		%	—			—			1.7		%	2.7		%	—

The following table presents information regarding our forward-starting interest rate swap agreements:



Notional Amount as of December 31,				Period of Hedge	Weighted-Average Fixed Rate		Fair Value as of December 31,
2018		2017		Period of Hedge	Weighted-Average Fixed Rate		2018			2017
(Thousands of Dollars)							(Thousands of Dollars)
$	—	$	350,000	04/2018 - 04/2028	2.6	%	$	—		$	(5,394	)
250,000		250,000		09/2020 - 09/2030	2.8	%	(124		)	(4,594		)
$	250,000	$	600,000				$	(124	)	$	(9,988	)

Commodity Price Risk

Since the operations of our fuels marketing segment expose us to commodity price risk, we use derivative instruments to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Please refer to our derivative financial instruments accounting policy in Notes 2 and 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information on our various types of derivatives.

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We have a risk management committee that oversees our trading policies and procedures and certain aspects of risk management. Our risk management committee also reviews all new risk management strategies in accordance with our risk management policy, as approved by our board of directors.

The commodity contracts disclosed below, all of which relate to refined products, represent only those contracts exposed to commodity price risk at the end of the period. Please refer to Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the volume and related fair value of all commodity contracts.



	December 31, 2018
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)
Fair Value Hedges:
Futures - long	7	$	69.74	N/A		$	6
Futures - short	50	N/A		$	72.61	$	104

Economic Hedges and Other Derivatives:
Futures - short	1	N/A		$	72.61	$	2
Swaps - long	143	$	50.13	N/A		$	(454	)
Swaps - short	103	N/A		$	50.46	$	333

Total fair value of open positions exposed to commodity price risk						$	(9	)



	December 31, 2017
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)
Fair Value Hedges:
Futures - long	2	$	86.88	N/A		$	—
Futures - short	5	N/A		$	85.59	$	(6	)
Swaps - short	149	N/A		$	55.79	$	(106	)

Economic Hedges and Other Derivatives:
Futures - long	10	$	86.13	N/A		$	7
Futures - short	14	N/A		$	85.76	$	(16	)
Swaps - long	196	$	55.05	N/A		$	264
Swaps - short	199	N/A		$	53.76	$	(525	)

Total fair value of open positions exposed to commodity price risk						$	(382	)

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s internal control over financial reporting as of December 31, 2018. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management believes that, as of December 31, 2018, our internal control over financial reporting was effective based on those criteria.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The effectiveness of internal control over financial reporting as of December 31, 2018 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 69.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries (the Partnership) as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2019 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2004.

San Antonio, Texas

February 28, 2019

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

Opinion on Internal Control Over Financial Reporting

We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2018, based on criteria established Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2019 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

San Antonio, Texas

February 28, 2019

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)



	December 31,
	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	13,644		$	24,292
Accounts receivable, net of allowance for doubtful accounts of $9,412 and $9,948 as of December 31, 2018 and 2017, respectively	148,308			176,570
Receivable from related party	—			205
Inventories	22,713			26,857
Prepaid and other current assets	17,493			22,508
Total current assets	202,158			250,432
Property, plant and equipment, at cost	6,338,312			6,243,481
Accumulated depreciation and amortization	(2,049,690		)	(1,942,548		)
Property, plant and equipment, net	4,288,622			4,300,933
Intangible assets, net	733,056			784,479
Goodwill	1,036,976			1,097,475
Deferred income tax asset	—			233
Other long-term assets, net	88,328			101,681
Total assets	$	6,349,140		$	6,535,233
Liabilities, Mezzanine Equity and Partners’ Equity
Current liabilities:
Accounts payable	$	143,121		$	145,932
Short-term debt	18,500			35,000
Current portion of long-term debt	—			349,990
Accrued interest payable	36,293			40,449
Accrued liabilities	101,993			61,578
Taxes other than income tax	19,083			14,385
Income tax payable	4,445			4,172
Total current liabilities	323,435			651,506
Long-term debt, less current portion	3,111,996			3,263,069
Deferred income tax liability	12,428			22,272
Other long-term liabilities	79,558			118,297
Total liabilities	3,527,417			4,055,144

Commitments and contingencies (Note 15)

Series D preferred limited partners (23,246,650 preferred units outstanding as of December 31, 2018) (Note 19)	563,992			—

Partners’ equity (Note 20):
Preferred limited partners (9,060,000 Series A preferred units, 15,400,000 Series B preferred units and 6,900,000 Series C preferred units outstanding as of December 31, 2018 and 2017)	756,301			756,603
Common limited partners (107,225,156 and 93,176,683 common units outstanding as of December 31, 2018 and 2017, respectively)	1,556,308			1,770,587
General partner	—			37,826
Accumulated other comprehensive loss	(54,878		)	(84,927		)
Total partners’ equity	2,257,731			2,480,089
Total liabilities, mezzanine equity and partners’ equity	$	6,349,140		$	6,535,233

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars, Except Unit and Per Unit Data)



	Year Ended December 31,
	2018			2017			2016
Revenues:
Service revenues	$	1,206,981		$	1,128,726		$	1,083,165
Product sales	754,776			685,293			673,517
Total revenues	1,961,757			1,814,019			1,756,682
Costs and expenses:
Costs associated with service revenues:
Operating expenses (excluding depreciation and amortization expense):
Third parties	488,174			449,670			426,686
Related party	—			—			21,681
Total operating expenses	488,174			449,670			448,367
Depreciation and amortization expense	288,999			255,534			208,217
Total costs associated with service revenues	777,173			705,204			656,584
Cost of product sales	705,946			651,599			633,653
General and administrative expenses (excluding depreciation and amortization expense):
Third parties	106,200			112,240			88,324
Related party	—			—			10,493
Total general and administrative expenses	106,200			112,240			98,817
Other depreciation and amortization expense	8,875			8,698			8,519
Total costs and expenses	1,598,194			1,477,741			1,397,573
Operating income	363,563			336,278			359,109
Interest expense, net	(186,237		)	(173,083		)	(138,350		)
Other income (expense), net	39,876			(5,294		)	(58,783		)
Income before income tax expense	217,202			157,901			161,976
Income tax expense	11,408			9,937			11,973
Net income	$	205,794		$	147,964		$	150,003

Basic and diluted net (loss) income per common unit (Note 21)	$	(2.77	)	$	0.64		$	1.27
Basic weighted-average common units outstanding	99,490,495			88,825,964			78,080,484
Diluted weighted-average common units outstanding	99,531,172			88,825,964			78,113,002

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of Dollars)



	Year Ended December 31,
	2018		2017			2016
Net income	$	205,794	$	147,964		$	150,003
Other comprehensive income (loss):
Foreign currency translation adjustment	4,304		17,466			(8,243		)
Net gain (loss) on pension and other postretirement benefit adjustments, net of income tax (expense) benefit of ($94), $184 and $60	2,334		(6,170		)	(2,850		)
Net gain (loss) on cash flow hedges	23,411		(2,046		)	5,710
Total other comprehensive income (loss)	30,049		9,250			(5,383		)
Comprehensive income	$	235,843	$	157,214		$	144,620

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)



	Year Ended December 31,
	2018			2017			2016
Cash Flows from Operating Activities:
Net income	$	205,794		$	147,964		$	150,003
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	297,874			264,232			216,736
Unit-based compensation expense	12,004			8,132			7,579
Amortization of debt related items	7,388			6,147			7,477
Loss from sale of European operations	43,366			—			—
(Gain) loss from sale or disposition of assets	(2,094		)	4,984			64
Gain from insurance recoveries	(78,756		)	—			—
Impairment loss	—			—			58,655
Deferred income tax expense (benefit)	2,043			6			(469		)
Changes in current assets and current liabilities (Note 22)	78,262			(26,493		)	3,716
(Increase) decrease in other long-term assets	(3,029		)	943			18,021
(Decrease) increase in other long-term liabilities	(17,832		)	2,414			(23,408		)
Other, net	(813		)	(1,530		)	(1,613		)
Net cash provided by operating activities	544,207			406,799			436,761
Cash Flows from Investing Activities:
Capital expenditures	(457,452		)	(384,638		)	(204,358		)
Change in accounts payable related to capital expenditures	(7,683		)	36,903			(11,063		)
Acquisitions	(37,502		)	(1,461,719		)	(95,657		)
Proceeds from Axeon term loan	—			110,000			—
Proceeds from insurance recoveries	78,419			977			—
Proceeds from sale of European operations	266,740			—			—
Proceeds from sale or disposition of assets	3,700			2,036			—
Net cash used in investing activities	(153,778		)	(1,696,441		)	(311,078		)
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings	1,254,153			1,465,767			752,729
Proceeds from short-term debt borrowings	618,500			1,051,000			654,000
Proceeds from note offering, net of issuance costs	—			543,333			—
Long-term debt repayments	(1,746,776		)	(1,417,539		)	(772,152		)
Short-term debt repayments	(635,000		)	(1,070,000		)	(684,000		)
Proceeds from issuance of Series D preferred units	590,000			—			—
Payment of issuance costs for Series D preferred units	(34,203		)	—			—
Proceeds from issuance of other preferred units, net of issuance costs	—			538,560			218,400
Proceeds from issuance of common units, net of issuance costs	10,000			643,878			27,710
Contributions from general partner	204			13,737			680
Distributions to preferred unitholders	(90,670		)	(38,833		)	—
Distributions to common unitholders and general partner	(300,777		)	(446,306		)	(392,962		)
Cash consideration for Merger (Note 4)	(67,795		)	—			—
Proceeds from termination of interest rate swaps	8,048			—			—
Increase (decrease) in cash book overdrafts	2,935			1,736			(11,237		)
Other, net	(8,486		)	(9,061		)	(4,492		)
Net cash (used in) provided by financing activities	(399,867		)	1,276,272			(211,324		)
Effect of foreign exchange rate changes on cash	(1,210		)	1,720			2,721
Net decrease in cash and cash equivalents	(10,648		)	(11,650		)	(82,920		)
Cash and cash equivalents as of the beginning of the period	24,292			35,942			118,862
Cash and cash equivalents as of the end of the period	$	13,644		$	24,292		$	35,942

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND MEZZANINE EQUITY

Years Ended December 31, 2018, 2017 and 2016

(Thousands of Dollars)



	Limited Partners															Mezzanine Equity
	Preferred			Common			General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Equity (Note 20)			Series D Preferred Limited Partners (Note 19)			Total
Balance as of January 1, 2016	$	—		$	1,661,900		$	36,738		$	(88,794	)	$	1,609,844		$	—		$	1,609,844
Net income	1,925			102,580			45,498			—			150,003			—			150,003
Other comprehensive loss	—			—			—			(5,383		)	(5,383		)	—			(5,383		)
Distributions to partners	(1,925		)	(341,798		)	(51,164		)	—			(394,887		)	—			(394,887		)
Issuance of common units, including contribution from general partner	—			27,710			575			—			28,285			—			28,285
Issuance of preferred units	218,400			—			—			—			218,400			—			218,400
Unit-based compensation	—			5,250			105			—			5,355			—			5,355
Balance as of December 31, 2016	218,400			1,455,642			31,752			(94,177		)	1,611,617			—			1,611,617
Net income	40,448			60,610			46,906			—			147,964			—			147,964
Other comprehensive income	—			—			—			9,250			9,250			—			9,250
Distributions to partners	(40,448		)	(391,737		)	(54,569		)	—			(486,754		)	—			(486,754		)
Issuance of common units, including contribution from general partner	—			643,878			13,597			—			657,475			—			657,475
Issuance of preferred units	538,560			—			—			—			538,560			—			538,560
Unit-based compensation	—			2,516			140			—			2,656			—			2,656
Other	(357		)	(322		)	—			—			(679		)	—			(679		)
Balance as of December 31, 2017	756,603			1,770,587			37,826			(84,927		)	2,480,089			—			2,480,089
Net income	64,091			110,788			2,466			—			177,345			28,449			205,794
Other comprehensive income	—			—			—			30,049			30,049			—			30,049
Distributions to partners	(64,091		)	(286,398		)	(14,379		)	—			(364,868		)	(28,449		)	(393,317		)
Issuance of common units, including contribution from general partner	—			10,000			204			—			10,204			—			10,204
Issuance of Series D preferred units	—			—			—			—			—			555,797			555,797
Unit-based compensation	—			7,925			—			—			7,925			—			7,925
Adjustments related to the Merger (refer to Note 4 for discussion)	—			(41,973		)	(25,999		)	—			(67,972		)	—			(67,972		)
Series D Preferred Unit accretion (refer to Note 19 for discussion)	—			(8,195		)	—			—			(8,195		)	8,195			—
Other	(302		)	(6,426		)	(118		)	—			(6,846		)	—			(6,846		)
Balance as of December 31, 2018	$	756,301		$	1,556,308		$	—		$	(54,878	)	$	2,257,731		$	563,992		$	2,821,723

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2018, 2017 and 2016

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. As a result of the merger described below, NuStar GP Holdings, LLC (NuStar GP Holdings or NSH), which indirectly owns our general partner, became a wholly owned subsidiary of ours on July 20, 2018.

Recent Developments

Merger. On July 20, 2018, we completed the merger of NSH with a subsidiary of NS. Under the terms of the merger agreement, NSH unitholders received 0.55 of a common unit representing a limited partner interest in NS in exchange for each NSH unit owned at the effective time of the merger. Please refer to Note 4 for further discussion of the merger.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million. See Note 19 for further discussion. On June 29, 2018, we also issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC.

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including our St. Eustatius terminal, which experienced the most damage and was temporarily shut down. The damage caused by the Caribbean hurricane resulted in lower revenues for our bunker fuel operations in our fuels marketing segment and lower throughput and associated handling fees in our storage segment in 2017 and in the first quarter of 2018. In 2017, we recorded a $5.0 million loss in “Other income (expense), net” in the consolidated statements of income for property damage at the terminal, which represents the amount of our property deductible under our insurance policy, and we received $12.5 million of insurance proceeds, of which $3.8 million was for business interruption. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal, of which $9.1 million related to business interruption. Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. We recorded a $78.8 million gain in “Other income (expense), net” in the consolidated statements of income in the first quarter of 2018 for the amount by which the insurance proceeds exceeded our expenses incurred during the period. Although the repairs are not complete, we expect that the costs to repair the property damage at the terminal will not exceed the amount of insurance proceeds received.

Other Events

Navigator Acquisition and Financing Transactions. On May 4, 2017, we acquired Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. Please refer to Notes 5, 13 and 20 for further discussion.

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Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the Fifth Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP) and other employee benefit plans. Please refer to Note 4 for further discussion of the Employee Transfer and our related party agreements, Note 23 for a discussion of our employee benefit plans and Note 24 for a discussion of our long-term incentive plans.

Operations

We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.

Pipeline. We own 3,130 miles of refined product pipelines and 2,070 miles of crude oil pipelines, as well as approximately 5.0 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,600 miles of refined product pipelines, consisting of the East and North Pipelines, and a 2,000-mile ammonia pipeline, which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 7.3 million barrels. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.

Storage. We own terminal and storage facilities in the United States, Canada, Mexico and St. Eustatius in the Caribbean Netherlands, with approximately 75.8 million barrels of storage capacity. Our terminal and storage facilities provide storage, handling and other services on a fee basis for petroleum products, crude oil, specialty chemicals and other liquids.

Fuels Marketing. Prior to the third quarter of 2017, our fuels marketing operations involved the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other refined products for resale. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions were in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The remaining operations in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews its estimates based on currently available information. Management may revise estimates due to changes in facts and circumstances.

Cash and Cash Equivalents

Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.

Accounts Receivable

Trade receivables are carried at original invoice amount. We extend credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at the time of its review.

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Inventories

Inventories consist of petroleum products, materials and supplies. Inventories, except those associated with a qualifying fair value hedge, are valued at the lower of cost or net realizable value. Cost is determined using the weighted-average cost method. Our inventory, other than materials and supplies, consists of one end-product category, petroleum products, which we include in the fuels marketing segment. Accordingly, we determine lower of cost or net realizable value adjustments on an aggregate basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are valued at the lower of average cost or net realizable value.

Property, Plant and Equipment

We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost. Repair and maintenance costs associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred. Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related assets. When property or equipment is retired, sold or otherwise disposed of, the difference between the carrying value and the net proceeds is recognized in “Other income (expense), net” in the consolidated statements of income in the year of disposition.

We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and are amortized over the asset’s estimated useful life as a component of depreciation expense.

Goodwill

We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. We performed a quantitative goodwill impairment test as of October 1, 2018 and 2017, and determined that no impairment charges existed.

We recognize an impairment of goodwill if the carrying value of goodwill exceeds its estimated fair value. In order to estimate the fair value of goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential.

We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent merger and acquisition transaction data of comparable entities.

Our reporting units to which goodwill has been allocated consist of the following:


•	crude oil pipelines;


•	refined product pipelines;


•	terminals, excluding our St. Eustatius and Point Tupper facilities and our refinery crude storage tanks; and


•	bunkering activity at our St. Eustatius and Point Tupper facilities.

The quantitative impairment test for goodwill consists of a two-step process. Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. The carrying value of each reporting unit equals the total identified assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner. If the carrying value exceeds fair value, there is a potential impairment and step 2 must be performed to determine the amount of goodwill impairment. Step 2 compares the carrying value of the reporting unit’s goodwill to its implied fair value using a hypothetical allocation of the reporting unit’s fair value. If the goodwill carrying value exceeds its implied fair value, the excess is reported as impairment.

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Unit is sensitive to typical valuation assumptions, particularly future earnings and cash flows. Recently, the earnings of our Statia Bunkering Reporting Unit have declined compared to historical norms, mostly due to the continued impact from hurricanes that damaged much of the infrastructure in the Caribbean. Our estimates assume the earnings of the Statia Bunkering Reporting Unit return to those historical levels in the near term. However, if there is a prolonged reduction in our earnings from the lingering effect described above, or other factors that result in a slower than anticipated recovery in our earnings, it could result in a reduction of our estimated fair value of the Statia Bunkering Reporting Unit to an amount less than its carrying value. We will continue to monitor the business and consider additional interim analysis of goodwill as appropriate.

Impairment of Long-Lived Assets

We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell. We believe that the carrying amounts of our long-lived assets as of December 31, 2018 are recoverable.

Income Taxes

We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the federal and state income tax returns of our partners. For transfers of publicly held common units subsequent to our initial public offering, we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of assets, based upon the new unitholder’s purchase price for the common units.

We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, 2018 and 2017.

NuStar Energy and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. For U.S. federal and state purposes, as well as for our major non-U.S. jurisdictions, tax years subject to examination are 2015 through 2017, according to standard statute of limitations.

Asset Retirement Obligations

We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.

We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair value of these costs.

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We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded liabilities of $0.2 million and $0.7 million as of December 31, 2018 and 2017, respectively, which are included in “Other long-term liabilities” in the consolidated balance sheets, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements.

Environmental Remediation Costs

Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods.

Product Imbalances

We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations due to pressure and temperature changes. Pursuant to the new revenue recognition standard we adopted January 1, 2018, we no longer recognize the fair value of product imbalances on our consolidated balance sheets. Prior to adoption, we used quoted market prices as of the reporting date to value our assets and liabilities related to product imbalances. Product imbalance liabilities were included in “Accrued liabilities” and product imbalance assets were included in “Other current assets” in the consolidated balance sheets.

Revenue Recognition

Revenue-Generating Activities. Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff.

Revenues for the storage segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees, and certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services (all of which are considered optional services).

Revenues for the fuels marketing segment are derived from the sale of petroleum products.

Within our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments (MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange, those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.

Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume.

Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.

Adoption of ASC Topic 606. On January 1, 2018, we adopted Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC Topic 606) using the modified retrospective method and applied ASC Topic 606 to all revenue contracts with customers. After identifying a contract with a customer, ASC Topic 606 requires us to (i) identify the performance obligations in the contract; (ii) determine the transaction price; (iii) allocate the transaction price to the performance obligations; and (iv) recognize revenue when or as we satisfy a performance obligation. For the majority of our

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contracts, we recognize revenue in the amount to which we have a right to invoice. Generally, payment terms do not exceed 30 days.

Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the pipelines. Similarly, the performance obligation for our storage segment consists of multiple activities necessary to receive, store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues). Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services represents a material right to the customer, which results in a second performance obligation in those contracts.

Product sales contracts associated with our fuels marketing segment generally include a single performance obligation to deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer obtains control of the commodity.

Optional services do not provide a material right to the customer, and are not considered a separate performance obligation in the contract. If and when a customer elects an optional service, it becomes part of the existing performance obligation.

Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we determine the transaction price based on our right to invoice the customer for the value of services provided to the customer for the applicable period.

In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in the transaction price of the underlying service contract.

We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value-added and some excise taxes. These taxes are not included in the transaction price and are, therefore, excluded from revenues.

Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance obligations. We base our estimates on our analysis of expected future production information available from our customers or other sources, which we update at least quarterly.

Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods (the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the customer cannot or will not utilize the deficiency payment (i.e. breakage). If our contract does not allow the customer to apply deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the performance obligation.

Income Allocation

Our partnership agreement contains provisions for the allocation of net income to the unitholders and, prior to the merger with our general partner, to the general partner. Our net income for each quarterly reporting period is first allocated to the preferred limited partner unitholders in an amount equal to the earned distributions for the respective reporting period and, prior to the

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merger, then to the general partner in an amount equal to the general partner’s incentive distribution calculated based upon the declared distribution for the respective reporting period. We allocate the remaining net income or loss among the common unitholders. Prior to the merger, we allocated the remaining net income or loss among the common unitholders (98%) and general partner (2%). See Note 4 for further discussion of the merger and Note 20 for the calculation of net income applicable to the general partner prior to the merger.

Basic and Diluted Net (Loss) Income Per Common Unit

Basic and diluted net (loss) income per common unit are determined pursuant to the two-class method. Under this method, all earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include restricted units awarded under our long-term incentive plans and, prior to the merger with our general partner, included our general partner’s interest.

We compute basic net (loss) income per common unit by dividing net (loss) income attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net (loss) income per common unit by dividing net (loss) income attributable to our common limited partners by the sum of (i) the weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and the Series D Preferred Units. See Note 24 for additional information on our performance units, Note 19 for additional information on our Series D Preferred Units and Note 21 for the calculation of basic and diluted net (loss) income per common unit.

Derivative Financial Instruments

We formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows or the fair value of the hedged items. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting. To assess the effectiveness of the hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the changes in the fair values of the derivative instrument and related hedged item.

We record commodity derivative instruments in the consolidated balance sheets at fair value. We recognize mark-to-market adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For derivative instruments that have associated underlying physical inventory but do not qualify for hedge accounting (Economic Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product sales.”

Under the terms of our forward-starting interest rate swap agreements, we pay a fixed rate and receive a variable rate. We entered into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. For forward-starting interest rate swaps designated and qualifying as cash flow hedges (Cash Flow Hedges), we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record the effective portion of mark-to-market adjustments as a component of accumulated other comprehensive income (loss) (AOCI), and any hedge ineffectiveness is recognized immediately in “Interest expense, net.” The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur.

We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which are included in cash flows from financing activities. See Note 17 for additional information regarding our derivative financial instruments.

Unit-based Compensation

Unit-based compensation for our long-term incentive plans is recorded in our consolidated balance sheets based on the fair value of the awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense when they occur. Unit-based compensation expense is included in “General and administrative expenses” on our consolidated statements of income. See Note 24 for additional information regarding our unit-based compensation.

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Margin Deposits

Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of the contracts. Margin deposits are included in “Other current assets” in the consolidated balance sheets.

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located, except for our subsidiaries located in St. Eustatius in the Caribbean Netherlands (formerly the Netherlands Antilles), whose functional currency is the U.S. dollar. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other income (expense), net” in the consolidated statements of income.

3. NEW ACCOUNTING PRONOUNCEMENTS

Securities and Exchange Commission Disclosure Update and Simplification

In August 2018, the Securities and Exchange Commission (SEC) issued final rules regarding disclosure requirements that were redundant, duplicative, overlapping or superseded by other SEC requirements or GAAP. The final rules primarily eliminated or reduced certain disclosure requirements, although they also required some additional disclosures. The guidance became effective on November 5, 2018, with an exception for the new disclosure requirement to present changes in partners’ equity in interim periods, which permits entities to begin disclosing this information in the quarter that begins after the effective date of the final rules. We elected to utilize this exception, and will begin presenting statements of partners’ equity on an interim basis beginning with the quarter ending March 31, 2019. These final rules did not have an impact on our financial position or results of operations.

Cloud Computing Arrangements

In August 2018, the Financial Accounting Standards Board (FASB) issued guidance addressing a customer’s accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is considered a service contract. Under the new guidance, implementation costs for a CCA should be evaluated for capitalization using the same approach as implementation costs associated with internal-use software and expensed over the term of the hosting arrangement. The guidance is effective for annual and interim periods beginning after December 15, 2019, with early adoption permitted. Prospective adoption for eligible costs incurred on or after the date of adoption or retrospective adoption are permitted. We are currently evaluating whether we will adopt these provisions early and whether we will elect prospective or retrospective adoption, but we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.

Disclosures for Defined Benefit Plans

In August 2018, the FASB issued amended guidance that makes minor changes to the disclosure requirements for employers that sponsor defined benefit pension and/or other postretirement benefit plans. The guidance is effective for annual periods beginning after December 15, 2020, with early adoption permitted, using a retrospective approach. We are currently evaluating whether we will adopt these provisions early, but we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.

Unit-Based Payments to Nonemployees

In June 2018, the FASB issued amended guidance which aligns the measurement and classification guidance for unit-based payments to nonemployees with the guidance for unit-based payments to employees, with certain exceptions. Under the amended guidance, unit-based payment awards to nonemployees will be measured at their grant date fair value. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. We adopted these provisions on January 1, 2019, and the guidance did not have a material impact on our financial position, results of operations or disclosures.

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Comprehensive Income

In February 2018, the FASB issued amended guidance which provides an entity the option to reclassify stranded tax effects caused by the Tax Cuts and Jobs Act of 2017 (the Act) from accumulated other comprehensive income to retained earnings, and also requires certain additional disclosures about those stranded tax effects. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. The new requirements should be applied using one of two transition methods, either at the beginning of the period of adoption or retrospectively. We early adopted these provisions in the fourth quarter of 2018 by electing to reclassify the stranded tax effects caused by the Act from AOCI to common limited partners’ equity as of the beginning of the quarter. The guidance did not have a material impact on our financial position, results of operations or disclosures.

Derivatives and Hedging

In August 2017, the FASB issued amended guidance intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. The amended guidance also makes certain targeted improvements to simplify the application of current hedge accounting guidance. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Certain of the new requirements should be applied prospectively, while others should be applied using a modified retrospective transition method. We adopted the amended guidance on January 1, 2019, and it did not have a material impact on our financial position, results of operations or disclosures.

Defined Benefit Plans

In March 2017, the FASB issued amended guidance that changes the presentation of net periodic pension cost related to defined benefit plans. Under the amended guidance, the service cost component of net periodic benefit cost is presented in the same income statement line items as other current employee compensation costs, but the remaining components of net periodic benefit cost are presented outside of operating income. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We began reporting the remaining components of net periodic benefit cost in “Other income, net” in the consolidated statements of comprehensive income upon adoption of the amended guidance on January 1, 2018. We applied the amended guidance prospectively as it did not have a material impact on previous periods.

Goodwill

In January 2017, the FASB issued amended guidance that simplifies the accounting for goodwill impairment by eliminating step 2 of the goodwill impairment test. Under the amended guidance, goodwill impairment will be measured as the excess of the reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied prospectively. Early adoption is permitted for any impairment tests performed after January 1, 2017, and we are currently evaluating whether we will adopt these provisions early. Regardless of our decision, we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.

Credit Losses

In June 2016, the FASB issued amended guidance that requires the use of a “current expected loss” model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. We currently expect to adopt the amended guidance on January 1, 2020, and we are assessing the impact of this amended guidance on our financial position, results of operations and disclosures. We plan to provide additional information about the expected impact at a future date.

Leases

In February 2016, the FASB issued amended guidance that requires lessees to recognize the assets and liabilities that arise from most leases on the balance sheet. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The changes are effective for annual and interim periods beginning after December 15, 2018, and amendments should be applied using one of two modified retrospective transition methods.

We adopted these provisions on January 1, 2019 through a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The transition adjustment related to the adoption was immaterial. We elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed us to

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carry forward historical lease classification. We also elected the practical expedient related to land easements, which allowed us to carry forward our historical accounting treatment for land easements on existing agreements, and the practical expedient to not account for lease and non-lease components separately for most of our asset classes. Right-of-use assets were less than 5% of total assets as of January 1, 2019, and lease liabilities did not significantly differ from right-of-use assets. We do not expect the guidance to have a material impact on our results of operations or cash flows. We intend to provide additional disclosures as required by the new standard, which we are currently assessing, in our quarterly report on Form 10-Q for the first quarter of 2019.

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The standard is effective for public entities for annual and interim periods beginning after December 15, 2017, using one of two retrospective transition methods. We adopted these provisions January 1, 2018 using the modified retrospective approach. The transition adjustment related to the adoption was immaterial. Please refer to Note 6 for further discussion.

4. MERGER AND RELATED PARTY AGREEMENTS

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Merger Sub merged with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy became the sole member of NuStar GP Holdings following the Merger on July 20, 2018 (refer to Organizational Structure in Item 1. “Business” for charts depicting our organizational structure at December 31, 2018 and before the Merger). Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019.

At the effective time of the Merger, each outstanding NuStar GP Holdings common unit was converted into the right to receive 0.55 of a NuStar Energy common unit and all NuStar GP Holdings common units ceased to be outstanding. No fractional NuStar Energy common units were issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit received cash in lieu thereof. As a result of the Merger, we issued approximately 23.6 million NuStar Energy common units and cancelled the 10.2 million NuStar Energy common units owned by subsidiaries of NuStar GP Holdings, resulting in approximately 13.4 million incremental NuStar Energy common units outstanding after the Merger. In addition, we repaid NSH’s debt with borrowings under our revolving credit agreement and incurred transaction costs for aggregate cash consideration of approximately $68.0 million.

Also at the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units was converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards was determined pursuant to the 0.55 exchange ratio provided in the Merger Agreement.

Following the completion of the Merger, the NuStar GP, LLC board of directors consists of nine members, currently composed of the six members of the NuStar GP, LLC board of directors prior to the Merger and the three independent directors who served prior to the Merger on NuStar GP Holdings’ board of directors.

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We accounted for the Merger as an equity transaction similar to a redemption or induced conversion of preferred stock. The excess of (1) the fair value of the consideration transferred in exchange for the outstanding NSH units over (2) the carrying value of the general partner interest in the Partnership was subtracted from net income available to common unitholders in the calculation of net loss per common unit attributable to the Merger as follows (in thousands of dollars, except unit and per unit data):



Consideration transferred:
Fair value of incremental NS common units issued	$	335,106
NSH debt and assumed net current liabilities	52,075
Transaction costs	15,897
Total consideration	403,078

Carrying value of general partner interest	25,999
Loss to common unitholders attributable to the Merger	$	(377,079	)

For the year ended December 31, 2018:
Basic weighted-average common units outstanding	99,490,495
Loss per common unit attributable to the Merger	$	(3.79	)

Related Party Agreements with NSH

GP Services Agreement. Prior to the Employee Transfer discussed in Note 1, our operations were managed by NuStar GP, LLC under a services agreement effective January 1, 2008 pursuant to which employees of NuStar GP, LLC performed services for our U.S. operations. Employees of NuStar GP, LLC provided services to us and NuStar GP Holdings; therefore, we reimbursed NuStar GP, LLC for all employee costs incurred prior to the Employee Transfer, other than the expenses allocated to NuStar GP Holdings. For the year ended December 31, 2016, we incurred $21.7 million in operating expenses and $10.5 million in general and administrative expenses pertaining to our related party transactions prior to the Employee Transfer. In connection with the Employee Transfer, we entered into an Amended and Restated Services Agreement with NuStar GP, LLC, effective March 1, 2016 (the Amended GP Services Agreement), which provided that we furnish administrative services necessary to conduct the business of NuStar GP Holdings, and NuStar GP Holdings compensated us for these services for an annual fee of $1.0 million, subject to adjustment based on the annual merit increase percentage applicable to our employees for the most recently completed fiscal year and for changes in level of service. We terminated the Amended GP Services Agreement in conjunction with the Merger.

Assignment and Assumption Agreement. Also in connection with the Employee Transfer, we entered into an Assignment and Assumption Agreement with NuStar GP, LLC (the Assignment Agreement). Under the Assignment Agreement, NuStar GP, LLC assigned all of its employee benefit plans, programs, contracts, policies, and various of its other agreements and contracts with certain employees, affiliates and third-party service providers (collectively, the Assigned Programs) to NuStar Services Co. In addition, NuStar Services Co agreed to assume the sponsorship of and all obligations relating to the ongoing maintenance and administration of each of the plans and agreements in the Assigned Programs.

Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006. Under the Non-Compete Agreement, we had the right of first refusal with respect to the potential acquisition of assets related to the transportation, storage or terminalling of crude oil, feedstocks or refined products (including petrochemicals) in the United States and internationally. NuStar GP Holdings had a right of first refusal with respect to the potential acquisition of general partner and other equity interests in publicly traded partnerships under common ownership with the general partner interest. As a result of the Merger, the Non-Compete Agreement was terminated, effective July 20, 2018.

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5. DISPOSITION AND ACQUISITIONS

Disposition

Sale of European Operations. On November 30, 2018, we sold our European operations to Inter Terminals, Ltd. for approximately $270.0 million. The operations sold include six liquids storage terminals in the United Kingdom and one facility in Amsterdam, with total storage capacity of approximately 9.5 million barrels. We sold these non-core assets that were not synergistic with our other operations as part of our plan to significantly improve our debt metrics and partially fund capital projects to grow our core business. We recognized a non-cash loss of $43.4 million related to the sale in “Other income (expense), net” on our consolidated statement of income for the year ended December 31, 2018.

Acquisitions

Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-mile pipeline and 18 storage tanks, for approximately $37.5 million. The assets acquired and the results of operations are included in our pipeline segment from the date of acquisition. We accounted for this acquisition as an asset purchase.

Navigator Acquisition. On April 11, 2017, we entered into a Membership Interest Purchase and Sale Agreement (the Acquisition Agreement) with FR Navigator Holdings LLC to acquire (the Navigator Acquisition) all of the issued and outstanding limited liability company interests in Navigator Energy Services, LLC (Navigator) for approximately $1.5 billion. We closed the Navigator Acquisition on May 4, 2017. We acquired crude oil transportation, pipeline connection and storage assets located in the Midland Basin in West Texas that, together with the assets we have constructed through various expansion projects since the date of the Navigator Acquisition, we collectively refer to as our Permian Crude System. The assets acquired are included in our pipeline segment. The consolidated statements of income include the results of operations for Navigator commencing on May 4, 2017.

We accounted for the Navigator Acquisition using the acquisition method. The following table reflects the final purchase price allocation:



	Purchase Price Allocation
	(Thousands of Dollars)
Accounts receivable	$	4,747
Other current assets	2,359
Property, plant and equipment, net	376,690
Intangible assets (a)	700,000
Goodwill (b)	398,024
Other long-term assets, net	2,199
Current liabilities	(22,300		)
Purchase price allocation, net of cash acquired	$	1,461,719


(a)	Intangible assets, which consist of customer contracts and relationships, are amortized on a straight-line basis over a period of 20 years.


(b)	The goodwill acquired represents the expected benefit from entering new geographic areas and the anticipated opportunities to generate future cash flows from the assets acquired and potential future projects.

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The unaudited pro forma information for the years ended December 31, 2017 and 2016 below presents the combined historical financial information for Navigator and the Partnership for those periods. This information assumes:


•	we completed the Navigator Acquisition on January 1, 2016;


•	we issued approximately 14.4 million common units;


•	we received a contribution from our general partner of $13.6 million to maintain the 2% general partner economic interest it owned at that time;


•	we issued 15.4 million Series B Preferred Units;


•	we issued $550.0 million of 5.625% senior notes;


•	additional depreciation and amortization that would have been incurred assuming the fair value adjustments to property, plant and equipment and intangible assets reflected in the purchase price allocation above; and


•	we satisfied Navigator’s outstanding obligations under its revolving credit agreement.



	Year Ended December 31,
	2017		2016
	(Thousands of Dollars, Except Per Unit Data)
Revenues	$	1,828,418	$	1,782,932
Net income	$	127,433	$	78,664

Basic and diluted net income per common unit	$	0.31	$	0.01

The pro forma information for the year ended December 31, 2017 includes transaction costs of $14.1 million, which were directly attributable to the Navigator Acquisition. The pro forma information is unaudited and is not necessarily indicative of the results of operations that would have resulted had the Navigator Acquisition occurred on January 1, 2016 or that may result in the future.

6. REVENUE FROM CONTRACTS WITH CUSTOMERS

Transition

On January 1, 2018, we adopted ASC Topic 606 using the modified retrospective method and applied ASC Topic 606 to all revenue contracts with customers. Results for reporting periods beginning after January 1, 2018 are presented under ASC Topic 606. In accordance with the modified retrospective approach, prior period amounts were not adjusted and are reported under ASC Topic 605, “Revenue Recognition.” The adoption of ASC Topic 606 affected our consolidated statements of comprehensive income as follows:



	As Reported			Without Adoption of ASC Topic 606			Effect of Change Higher/(Lower)
	(Thousands of Dollars, Except Per Unit Data)
For the year ended December 31, 2018:
Revenues	$	1,961,757		$	1,967,942		$	(6,185	)
Operating income	$	363,563		$	369,748		$	(6,185	)
Net income	$	205,794		$	211,979		$	(6,185	)
Basic net loss per common unit	$	(2.77	)	$	(2.70	)	$	(0.07	)

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Contract Assets and Liabilities

The following table provides information about contract assets and contract liabilities from contracts with customers:



	Contract Assets			Contract Liabilities
	(Thousands of Dollars)
Balance as of January 1, 2018	$	2,127		$	(60,464	)

Additions	3,281			(83,243		)
Transfer to accounts receivable	(2,803		)	—
Transfer to revenues	—			57,826
Total activity	478			(25,417		)


Balance as of December 31, 2018	2,605			(85,881		)
Less current portion	2,066			(46,936		)
Noncurrent portion	$	539		$	(38,945	)

Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included in “Other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated balance sheet. Contract liabilities relate to payments received in advance of satisfying performance obligations under a contract, which mainly result from contracts with MVCs, contracts with an incentive pricing structure and CIAC payments. Current contract liabilities are included in “Accrued liabilities” and noncurrent contract liabilities are included in “Other long-term liabilities” on the consolidated balance sheet.

In the third quarter of 2018, we entered into an agreement whereby our customer transferred ownership of crude oil to us, and we agreed to sell the crude oil and apply the proceeds as a non-refundable, one-time payment of storage fees. At the time of the agreement, we recognized a contract liability of $37.5 million.

In the second quarter of 2018, one customer for whom we had recorded a contract liability to perform future services elected not to extend the term of its terminal storage contract, thus reducing our future performance obligation. As a result, we adjusted the related contract liability and recognized $9.0 million in revenue.

Remaining Performance Obligations

The following table presents our estimated revenue from contracts with customers for remaining performance obligations that has not yet been recognized, representing our contractually committed revenue as of December 31, 2018 (in thousands of dollars):



2019	$	473,027
2020	383,889
2021	261,900
2022	210,772
2023	162,952
Thereafter	361,153
Total	$	1,853,693

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to customer contracts that have fixed pricing and fixed volume terms and conditions, generally including contracts with MVC payment obligations.

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Disaggregation of Revenues

The following table disaggregates our revenues:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines (excluding lessor revenues)	$	248,261		$	187,874		$	154,543
Refined products and ammonia pipelines	362,750			328,414			331,107
Total pipeline segment revenues from contracts with customers	611,011			516,288			485,650
Lessor revenues	54			—			—
Total pipeline segment revenues	611,065			516,288			485,650

Storage segment:
Throughput terminals	83,157			85,927			117,586
Storage terminals (excluding lessor revenues)	482,944			491,900			492,456
Total storage segment revenues from contracts with customers	566,101			577,827			610,042
Lessor revenues	39,849			39,126			—
Total storage segment revenues	605,950			616,953			610,042

Fuels marketing segment revenues from contracts with customers	752,312			692,884			681,934

Consolidation and intersegment eliminations	(7,570		)	(12,106		)	(20,944		)

Total revenues	$	1,961,757		$	1,814,019		$	1,756,682

7. ALLOWANCE FOR DOUBTFUL ACCOUNTS

The changes in the allowance for doubtful accounts consisted of the following:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Balance as of beginning of year	$	9,948		$	7,756		$	8,473
Increase in allowance, net	755			2,217			24
Accounts charged against the allowance	(1,291		)	(25		)	(741		)
Balance as of end of year	$	9,412		$	9,948		$	7,756

8. INVENTORIES

Inventories consisted of the following:



	December 31,
	2018		2017
	(Thousands of Dollars)
Petroleum products	$	12,689	$	17,027
Materials and supplies	10,024		9,830
Total	$	22,713	$	26,857

We purchase petroleum products for resale. Our petroleum products consist of intermediates, gasoline, distillates and other petroleum products. Materials and supplies mainly consist of blending and additive chemicals and maintenance materials used in our pipeline and storage segments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	Estimated Useful Lives			December 31,
	Estimated Useful Lives			2018			2017
	(Years)			(Thousands of Dollars)
Land		-		$	143,477		$	143,527
Land and leasehold improvements	5	-	40	215,796			203,085
Buildings	15	-	40	160,069			151,702
Pipelines, storage and terminals	15	-	40	5,315,201			5,080,795
Rights-of-way	20	-	40	301,739			264,170
Construction in progress		-		202,030			400,202
Total				6,338,312			6,243,481
Less accumulated depreciation and amortization				(2,049,690		)	(1,942,548		)
Property, plant and equipment, net				$	4,288,622		$	4,300,933

Capitalized interest costs added to property, plant and equipment totaled $7.8 million, $5.5 million and $3.4 million for the years ended December 31, 2018, 2017 and 2016, respectively. Depreciation and amortization expense for property, plant and equipment totaled $243.5 million, $222.5 million and $200.7 million for the years ended December 31, 2018, 2017 and 2016, respectively.

10. INTANGIBLE ASSETS

Intangible assets consisted of the following:



		December 31, 2018					December 31, 2017
	Weighted-Average Amortization Period	Cost		Accumulated Amortization			Cost		Accumulated Amortization
	(Years)	(Thousands of Dollars)
Customer contracts and relationships	18	$	863,950	$	(132,509	)	$	863,950	$	(81,136	)
Other	47	2,359		(744		)	2,359		(694		)
Total		$	866,309	$	(133,253	)	$	866,309	$	(81,830	)

Intangible assets are recorded at fair value as of the date acquired. All of our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $51.4 million, $39.6 million and $13.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. The estimated aggregate amortization expense is approximately $51.0 million for each of the years 2019 through 2022, and approximately $45.0 million for 2023.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11. GOODWILL

Changes in the carrying amount of goodwill by segment were as follows:



	Pipeline			Storage			Fuels Marketing		Total
	(Thousands of Dollars)
Balances as of January 1, 2017:
Goodwill	$	306,207		$	663,760		$	31,123	$	1,001,090
Accumulated impairment losses	—			(304,453		)	—		(304,453		)
Net goodwill	306,207			359,307			31,123		696,637

Activity for the year ended December 31, 2017:
Navigator Acquisition preliminary purchase price allocation (a)	400,838			—			—		400,838

Balances as of December 31, 2017:
Goodwill	707,045			663,760			31,123		1,401,928
Accumulated impairment losses	—			(304,453		)	—		(304,453		)
Net goodwill	707,045			359,307			31,123		1,097,475

Activity for the year ended December 31, 2018:
Navigator Acquisition purchase price allocation adjustments (a)	(2,814		)	—			—		(2,814		)
Adjustment due to the sale of our European operations (a)	—			(57,685		)	—		(57,685		)

Balances as of December 31, 2018:
Goodwill	704,231			606,075			31,123		1,341,429
Accumulated impairment losses	—			(304,453		)	—		(304,453		)
Net goodwill	$	704,231		$	301,622		$	31,123	$	1,036,976


(a)	See Note 5 for discussion of the Navigator Acquisition and the sale of our European operations.

12. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	December 31,
	2018		2017
	(Thousands of Dollars)
Employee wages and benefit costs	$	30,720	$	16,963
Revenue contract liabilities	46,936		—
Deferred revenue	—		18,243
Other	24,337		26,372
Accrued liabilities	$	101,993	$	61,578

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13. DEBT

Long-term debt consisted of the following:



				December 31,
	Maturity			2018			2017
				(Thousands of Dollars)
Revolving Credit Agreement		2020		$	745,000		$	893,311
7.65% senior notes		2018		—			350,000
4.80% senior notes		2020		450,000			450,000
6.75% senior notes		2021		300,000			300,000
4.75% senior notes		2022		250,000			250,000
5.625% senior notes		2027		550,000			550,000
Subordinated Notes		2043		402,500			402,500
GoZone Bonds	2038	thru	2041	365,440			365,440
Receivables Financing Agreement		2020		61,800			62,300
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs		N/A		(12,744		)	(10,492		)
Total long-term debt				3,111,996			3,613,059
Less current portion				—			349,990
Long-term debt, less current portion				$	3,111,996		$	3,263,069

The long-term debt repayments are due as follows (in thousands of dollars):



2019	$	—
2020	1,256,800
2021	300,000
2022	250,000
2023	—
Thereafter	1,317,940
Total repayments	3,124,740
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs	(12,744		)
Total long-term debt	$	3,111,996

Interest payments totaled $190.9 million, $163.6 million and $146.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. We amortized an aggregate of $7.1 million, $5.0 million and $4.4 million of debt issuance costs and debt discount for the years ended December 31, 2018, 2017 and 2016, respectively.

Revolving Credit Agreement

On June 29, 2018, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement) to exclude the Series D Preferred Units from the definition of “Indebtedness.” Additionally, the amendment reduced the total amount available for borrowing from $1.75 billion to $1.575 billion, effective June 29, 2018, with a further reduction to $1.4 billion, effective December 28, 2018. The Revolving Credit Agreement was also amended to, among other things, add a minimum consolidated interest coverage ratio (as defined in the Revolving Credit Agreement), which must not be less than 1.75-to-1.00 for each rolling period of four quarters, beginning with the rolling period ending June 30, 2018.

On March 28, 2018, NuStar Logistics amended the Revolving Credit Agreement to increase the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) to 5.25-to-1.00 for the rolling periods ending June 30, 2018 through December 31, 2018. For any rolling periods ending on or after March 31, 2019, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00. If we complete one or more acquisitions for aggregate net consideration of at least $50.0 million, our maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. The Revolving Credit Agreement was also amended to, among other things, provide that the definition of “Change in Control” in the Revolving Credit Agreement excludes the Merger discussed in Note 4.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2018, we had $651.3 million available for borrowing. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. For the year ended December 31, 2018, we recorded deferred issuance costs of $4.0 million associated with the Revolving Credit Agreement to “Other long-term assets, net” on the consolidated balance sheet.

The Revolving Credit Agreement bears interest, at our option, based on an alternative base rate, a LIBOR-based rate or a EURIBOR-based rate. The interest rate on the Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2. This rating downgrade caused the interest rate on our Revolving Credit Agreement to increase by 0.25% effective February 2018. As of December 31, 2018, our weighted-average interest rate was 4.5%, and we had $745.0 million outstanding. During the year ended December 31, 2018, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 4.1%.

Notes

NuStar Logistics Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses. The interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017.

Interest is payable semi-annually in arrears for the $450.0 million of 4.80% senior notes, $300.0 million of 6.75% senior notes, $250.0 million of 4.75% senior notes and $550.0 million of 5.625% senior notes (collectively, the NuStar Logistics Senior Notes). The credit rating downgrade by Moody’s in February 2018 increased the interest rate on our $350.0 million of 7.65% senior notes by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018. We repaid these notes on April 15, 2018 with borrowings under our Revolving Credit Agreement.

The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur additional secured indebtedness unless the same security is also provided for the benefit of holders of the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens and to engage in certain sale-leaseback transactions. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the redemption date. If we undergo a change of control, as defined in the supplemental indentures for the 6.75% senior notes or the 5.625% senior notes, each holder of the 6.75% senior notes or the 5.625% senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes, plus any accrued and unpaid interest to the date of repurchase. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP.

NuStar Logistics Subordinated Notes. NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes are due January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured and subordinated basis by NuStar Energy and NuPOP. Effective January 15, 2018, the interest rate on the Subordinated Notes switched from a fixed annual rate of 7.625%, payable quarterly in arrears, to an annual rate equal to the sum of the three-month LIBOR for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the Subordinated Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional interest at a rate equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to defer interest payments, NuStar Energy cannot declare or make cash distributions to its unitholders during the period that interest payments are deferred. As of December 31, 2018, the interest rate was 9.2%.

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The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions. Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Gulf Opportunity Zone Revenue Bonds

In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of 2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). The interest rates on these bonds are based on a weekly tax-exempt bond market interest rate, and interest is paid monthly. Following the issuances, the proceeds were deposited with a trustee and are disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansions. We include the amount remaining in the trust in “Other long-term assets, net,” and we include the amount of bonds issued in “Long-term debt” in our consolidated balance sheets. We did not receive any proceeds from the trustee for the years ended December 31, 2018 and 2017.

NuStar Logistics is solely obligated to service the principal and interest payments associated with the GoZone Bonds. Letters of credit were issued by various individual banks on our behalf to guarantee the payment of interest and principal on the bonds. All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics and generally contain the same restrictive covenants, maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements as the Revolving Credit Agreement. Obligations under the letters of credit issued are guaranteed by NuStar Energy and NuPOP. The letters of credit issued by individual banks do not restrict the amount we can borrow under the Revolving Credit Agreement.

The following table summarizes the GoZone Bonds outstanding as of December 31, 2018:



Date Issued	Maturity Date	Amount Outstanding		Amount of Letter of Credit		Amount Received from Trustee		Amount Remaining in Trust (a)		Interest Rate (b)
		(Thousands of Dollars)
June 26, 2008	June 1, 2038	$	55,440	$	56,169	$	55,440	$	—	1.8	%
July 15, 2010	July 1, 2040	100,000		101,315		100,000		—		1.8	%
October 7, 2010	October 1, 2040	50,000		50,658		43,741		6,596		1.8	%
December 29, 2010	December 1, 2040	85,000		86,118		49,782		36,271		1.8	%
August 29, 2011	August 1, 2041	75,000		75,986		75,000		—		1.8	%
	Total	$	365,440	$	370,246	$	323,963	$	42,867


(a)	Amount remaining in trust includes accrued interest.


(b)	For the year ended December 31, 2018, our weighted-average interest rate on borrowings was 1.4%.

Receivables Financing Agreement

NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Logistics, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization Program. The March 28, 2018 amendment to the Revolving Credit Agreement also limits the amount of borrowings by NuStar Finance under the Receivables Financing Agreement to $125.0 million. The amount available for borrowing is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the claims of creditors of NuStar Energy, the Originators or their affiliates.

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On March 28, 2018, the Receivables Financing Agreement was amended to change the definition of Change in Control in the Receivables Financing Agreement such that the Merger discussed in Note 4 would not be a Change in Control for purposes of the Receivables Financing Agreement. On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. Borrowings by NuStar Finance under the Receivables Financing Agreement bear interest at the applicable bank rate, as defined under the Receivables Financing Agreement. As of December 31, 2018 and 2017, accounts receivable totaling $95.5 million and $92.6 million, respectively, were included in the Securitization Program. The weighted average interest rate related to outstanding borrowings under the Securitization Program during the year ended December 31, 2018 was 3.0%.

Short-Term Line of Credit

NuStar Logistics is party to a short-term line of credit agreement with an uncommitted borrowing capacity of up to $35.0 million, which allows us to better manage fluctuations in our daily cash requirements and minimize our excess cash balances. The interest rates and maturities vary and are determined at the time of borrowing. We had $18.5 million outstanding under this line of credit as of December 31, 2018. Obligations under this short-term line of credit agreement are guaranteed by NuStar Energy. As of December 31, 2018 and 2017, the weighted-average interest rates related to outstanding borrowings under our short-term line of credit were 4.4% and 3.2%, respectively.

14. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: The Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions along the routes of the systems.

Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

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The balance of and changes in the accruals for environmental matters were as follows:



	Year Ended December 31,
	2018			2017
	(Thousands of Dollars)
Balance as of the beginning of year	$	5,683		$	5,120
Additions to accrual	5,160			3,186
Payments	(3,058		)	(2,675		)
Foreign currency translation	(32		)	52
Balance as of the end of year	$	7,753		$	5,683

Accruals for environmental matters are included in the consolidated balance sheets as follows:



	December 31,
	2018		2017
	(Thousands of Dollars)
Accrued liabilities	$	4,349	$	3,054
Other long-term liabilities	3,404		2,629
Accruals for environmental matters	$	7,753	$	5,683

15. COMMITMENTS AND CONTINGENCIES

Contingencies

We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. We accrued $2.8 million and $7.3 million for contingent losses as of December 31, 2018 and 2017, respectively. The amount that will ultimately be paid related to such matters may differ from the recorded accruals, and the timing of such payments is uncertain. We evaluate each contingent loss at least quarterly, and more frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim or proceeding, or all matters in the aggregate, would have a material adverse effect on our results of operations, financial position or liquidity.

Commitments

Lessee and Other Commitments. Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2018 are as follows:



	Payments Due by Period
	2019		2020		2021		2022		2023		There- after		Total
	(Thousands of Dollars)
Operating leases	$	34,900	$	20,787	$	14,904	$	9,280	$	6,870	$	28,552	$	115,293
Purchase obligations	$	10,896	$	7,958	$	7,011	$	4,970	$	602	$	2,624	$	34,061

Rental expense for operating leases totaled $42.9 million, $36.2 million and $37.0 million for the years ended December 31, 2018, 2017 and 2016, respectively. Our operating leases consist primarily of the following:


•	two leases for tugs and barges utilized at our St. Eustatius facility for bunker fuel sales, with original terms of nine and ten years; and


•	land and dock leases at various terminal facilities, with original terms generally ranging from 5 to 40 years, including a build-to-suit lease with an initial term of five years and four additional five-year renewal periods that also includes a commitment for minimum dockage and wharfage throughput volumes.

Our purchase obligations primarily consist of an eleven-year chemical supply agreement related to our pipelines.

Lessor Revenues. We have entered into certain revenue arrangements where we are considered to be the lessor in accordance with GAAP. Under these arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual

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consumer price index adjustment. The arrangements commenced on January 1, 2017, and have initial terms of ten years with successive ten-year automatic renewal terms. We recognized $39.8 million of lease revenues from these leases for the year ended December 31, 2018, which is included in “Service revenues” in the consolidated statements of income. Future minimum revenues we expect to receive under these lease arrangements as of December 31, 2018 total $313.1 million, which we will recognize ratably over the following eight years. As of December 31, 2018, the cost and accumulated depreciation of leased storage assets totaled $233.2 million and $113.1 million, respectively.

16. FAIR VALUE MEASUREMENTS

We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated fair values.

Recurring Fair Value Measurements

The following assets and liabilities are measured at fair value on a recurring basis:



	December 31, 2018
	Level 1		Level 2			Level 3		Total
	(Thousands of Dollars)
Assets:
Other current assets:
Commodity derivatives	$	130	$	—		$	—	$	130
Other long-term assets, net:
Interest rate swaps	—		627			—		627
Total assets	$	130	$	627		$	—	$	757
Liabilities:
Other long-term liabilities:
Interest rate swaps	$	—	$	(751	)	$	—	$	(751	)



	December 31, 2017
	Level 1			Level 2			Level 3		Total
	(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances	$	3,890		$	—		$	—	$	3,890
Liabilities:
Accrued liabilities:
Product imbalances	$	(1,534	)	$	—		$	—	$	(1,534	)
Commodity derivatives	(878		)	—			—		(878		)
Interest rate swaps	—			(5,394		)	—		(5,394		)
Other long-term liabilities:
Interest rate swaps	—			(4,594		)	—		(4,594		)
Total liabilities	$	(2,412	)	$	(9,988	)	$	—	$	(12,400	)

Product Imbalances. Pursuant to the new revenue recognition standard we adopted January 1, 2018, we no longer recognize the fair value of product imbalances on our consolidated balance sheets. Prior to adoption, we valued our assets and liabilities related to product imbalances using quoted market prices in active markets as of the reporting date; accordingly, we included these product imbalances in Level 1 of the fair value hierarchy.

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Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an exchange; accordingly, we include these items in Level 1 of the fair value hierarchy. See Note 17 for a discussion of our derivative instruments.

Interest Rate Swaps. Because we estimate the fair value of our forward-starting interest rate swaps using discounted cash flows, which use observable inputs such as time to maturity and market interest rates, we include these interest rate swaps in Level 2 of the fair value hierarchy.

Fair Value of Financial Instruments

We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for long-term debt, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, including the current portion, were as follows:



	December 31, 2018		December 31, 2017
	(Thousands of Dollars)
Fair value	$	3,056,704	$	3,677,622
Carrying amount	$	3,111,996	$	3,613,059

We have estimated the fair value of our publicly traded notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded senior notes falls in Level 1 of the fair value hierarchy. With regard to our other debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls in Level 2 of the fair value hierarchy.

17. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES

We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.

Interest Rate Risk

We are a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which include forward-starting interest rate swap agreements related to a forecasted debt issuance in 2020. We entered into these swaps during the year ended December 31, 2015 in order to hedge the risk of fluctuations in the required interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. Under the terms of the swaps, we pay a fixed rate and receive a rate based on the three-month USD LIBOR. These swaps qualify as cash flow hedges, and we designate them as such. We record the effective portion of mark-to-market adjustments as a component of AOCI, and the amount in AOCI will be recognized in “Interest expense, net” as the forecasted interest payments occur or if the interest payments are probable not to occur. As of December 31, 2018 and 2017, the aggregate notional amount of forward-starting interest rate swaps totaled $250.0 million and $600.0 million, respectively. In April 2018, in connection with the maturity of the 7.65% senior notes due April 15, 2018, we terminated forward-starting interest rate swaps with an aggregate notional amount of $350.0 million and received $8.0 million. The termination payments are included in cash flows from financing activities on the consolidated statements of cash flows. During the third and fourth quarters of 2018, we determined that two forecasted interest payments were probable not to occur, and we reclassified $0.4 million from AOCI to “Interest expense, net.”

The remaining fair value amount associated with unwound fixed-to-floating interest rate swap agreements totaled $10.5 million and $15.6 million as of December 31, 2018 and 2017, respectively; these assets are included in “Long-term debt” on the consolidated balance sheets. The remaining fair value amount associated with unwound forward-starting interest rate swap agreements totaled $0.8 million and $14.3 million as of December 31, 2018 and 2017, respectively; these losses are included in AOCI on the consolidated balance sheets. These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the consolidated statements of income.

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Commodity Price Risk

We are exposed to market risks related to the volatility of petroleum product prices. In order to reduce the risk of commodity price fluctuations with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories, we utilize commodity futures and swap contracts, which qualify, and we designate, as fair value hedges. Derivatives that are intended to hedge our commodity price risk but fail to qualify as fair value hedges are considered economic hedges, and we record associated gains and losses in net income. Our risk management committee oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also reviews all new commodity and trading risk management strategies in accordance with our risk management policy, as approved by our board of directors. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017, thereby reducing our overall hedging activity.

The volume of commodity contracts is based on open derivative positions and represents the combined volume of our long and short open positions on an absolute basis, which totaled 0.7 million barrels and 1.2 million barrels as of December 31, 2018 and 2017, respectively. We had no margin deposits as of December 31, 2018 and $0.3 million of margin deposits as of December 31, 2017.

The fair values of our derivative instruments included in our consolidated balance sheets were as follows:



		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31,
	Balance Sheet Location	2018		2017		2018			2017
		(Thousands of Dollars)
Derivatives Designated as Hedging Instruments:
Commodity contracts	Other current assets	$	109	$	—	$	—		$	—
Interest rate swaps	Other long-term assets, net	627		—		—			—
Commodity contracts	Accrued liabilities	—		—		—			(112		)
Interest rate swaps	Accrued liabilities	—		—		—			(5,394		)
Interest rate swaps	Other long-term liabilities	—		—		(751		)	(4,594		)
Total		736		—		(751		)	(10,100		)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Other current assets	1,652		—		(1,631		)	—
Commodity contracts	Accrued liabilities	—		742		—			(1,508		)
Total		1,652		742		(1,631		)	(1,508		)

Total Derivatives		$	2,388	$	742	$	(2,382	)	$	(11,608	)

Certain of our derivative instruments are eligible for offset in the consolidated balance sheets and subject to master netting arrangements. Under our master netting arrangements, there is a legally enforceable right to offset amounts, and we intend to settle such amounts on a net basis. The following are the net amounts presented on the consolidated balance sheets:



	December 31,
Commodity Contracts	2018		2017
	(Thousands of Dollars)
Net amounts of assets presented in the consolidated balance sheets	$	130	$	—
Net amounts of liabilities presented in the consolidated balance sheets	$	—	$	(878	)

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We recognize the impact of our commodity contracts on earnings in “Cost of product sales” on the consolidated income statements, and that impact was as follows:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Derivatives Designated as Fair Value Hedging Instruments:
(Loss) gain recognized in income on derivative	$	(535	)	$	806		$	(11,254	)
(Loss) gain recognized in income on hedged item	(181		)	(656		)	15,295
(Loss) gain recognized in income for ineffective portion	$	(716	)	$	150		$	4,041

Derivatives Not Designated as Hedging Instruments:
(Loss) gain recognized in income on derivative	$	(601	)	$	(668	)	$	225

Our interest rate swaps had the following impact on earnings:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Derivatives Designated as Cash Flow Hedging Instruments:
Gain (loss) recognized in other comprehensive income (loss) on derivative (effective portion)	$	17,912		$	(8,670	)	$	(2,621	)
Loss reclassified from AOCI into interest expense, net (effective portion)	$	(5,499	)	$	(6,624	)	$	(8,331	)

As of December 31, 2018, we expect to reclassify a loss of $3.5 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swaps.

18. OTHER INCOME (EXPENSE)

Other income (expense) consisted of the following:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Gain (loss) related to hurricane activity	$	78,756		$	(5,000	)	$	—
Impairment loss on Axeon Term Loan	—			—			(58,655		)
Loss on sale of European operations	(43,366		)	—			—
Other, net	4,486			(294		)	(128		)
Other income (expense), net	$	39,876		$	(5,294	)	$	(58,783	)

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including our St. Eustatius terminal, which experienced the most damage and was temporarily shut down. In 2017, we recorded a $5.0 million loss in “Other income (expense), net” in the consolidated statements of income for property damage at the terminal. In 2018, we recorded a $78.8 million gain in “Other income (expense), net” in the consolidated statements of income following the settlement of our property damage claim for our St. Eustatius terminal. See Note 1 for additional information.

Axeon Term Loan. In December 2016, Lindsay Goldberg LLC, the private investment firm that owned Axeon, informed us that they entered into an agreement to sell Axeon’s retail asphalt sales and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter Agreement) to settle and terminate the Axeon Term Loan for a $110.0 million payment to us upon closing of the Axeon Sale. Therefore, we recorded a charge of $58.7 million, included in “Other income (expense), net” in the consolidated statements of income, to reduce the carrying amount of the Axeon Term Loan to $110.0 million. The Axeon Sale closed on February 22, 2017, at which time we received the $110.0 million payment in

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accordance with the Axeon Letter Agreement. Furthermore, the Axeon Term Loan and our obligation to provide ongoing credit support to Axeon all terminated concurrently on February 22, 2017.

19. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS

Purchase Agreement and Issuance of Series D Preferred Units

On June 26, 2018, the Partnership entered into a purchase agreement (the Series D Preferred Unit Purchase Agreement) with investment funds, accounts and entities (collectively, the Purchasers) managed by EIG Management Company, LLC and FS/EIG Advisors, LLC to issue and sell $590.0 million of Series D Preferred Units in a private placement. The Partnership issued a total of 23,246,650 Series D Preferred Units to the Purchasers at a price of $25.38 per Series D Preferred Unit (the Series D Preferred Unit Purchase Price). At the initial closing on June 29, 2018 (the Initial Closing), the Purchasers purchased 15,760,441 Series D Preferred Units for $400.0 million, and we received net proceeds of $370.7 million. The Purchasers purchased the remaining 7,486,209 Series D Preferred Units for $190.0 million at a second closing on July 13, 2018. The net proceeds to the Partnership from the sale of the Series D Preferred Units of $555.8 million, including deductions for a 3.5% transaction fee of $20.7 million paid to the Purchasers and other issuance costs of $13.5 million, were used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement.

Series D Preferred Units Rights

At the Initial Closing and pursuant to the Series D Preferred Unit Purchase Agreement, the Partnership amended and restated its partnership agreement to authorize and establish the rights, preferences and privileges of the Series D Preferred Units. The Series D Preferred Units rank equal to other classes of preferred units and senior to common units in the Partnership with respect to distribution rights and rights upon liquidation. The Series D Preferred Units generally will vote on an as-converted basis with the common units and will have certain class voting rights with respect to a limited number of matters as set forth in the partnership agreement.

Series D Preferred Units Distributions

Distributions on the Series D Preferred Units accrue and are cumulative from the issuance dates and are payable on the 15th day (or next business day) of each of March, June, September and December, beginning September 17, 2018 to holders of record on the first business day of each payment month. The distribution rate on the Series D Preferred Units is: (i) 9.75% per annum for the first two years; (ii) 10.75% per annum for years three through five; and (iii) the greater of 13.75% per annum or the distribution per common unit thereafter. While the Series D Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution payment date. For the four distribution periods beginning with the initial Series D Preferred Unit distribution, the Series D Preferred Unit distributions may be paid, in the Partnership’s sole discretion, in (i) cash or (ii) a combination of additional Series D Preferred Units and cash, provided that up to 50% of the distribution amount may be paid in additional Series D Preferred Units. Thereafter, any Series D Preferred Unit distributions in excess of $0.635 per unit may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the remainder paid in cash.

If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the applicable distribution rate for each of those distribution periods shall be increased by $0.048 per Series D Preferred Unit. In addition, if we fail to pay in full any Series D Preferred Unit distribution amount for three consecutive distribution periods, then until we pay such distributions in full: (i) each holder of the Series D Preferred Units may elect to convert its Series D Preferred Units into common units on a one-for-one basis, plus any unpaid Series D distributions, (ii) one person selected by the holders holding a majority of the outstanding Series D Preferred Units shall become an additional member of our board of directors and (iii) we will not be permitted to incur any indebtedness (as defined in the Revolving Credit Agreement) or engage in any acquisitions or asset sales in excess of $50.0 million without the consent of the holders holding a majority of the outstanding Series D Preferred Units. In addition, we will permanently lose the ability to pay any part of the distributions on the Series D Preferred Units in the form of additional Series D Preferred Units.

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The following table summarizes information about cash distributions declared for our Series D Preferred Units:



Period	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 15, 2018 - March 14, 2019	$	0.619	$	14,390	March 1, 2019	March 15, 2019
September 15, 2018 - December 14, 2018	$	0.619	$	14,390	December 3, 2018	December 17, 2018
July 13, 2018 - September 14, 2018 (a)	$	0.431	$	3,227	September 4, 2018	September 17, 2018
June 29, 2018 - September 14, 2018 (b)	$	0.525	$	8,274	September 4, 2018	September 17, 2018


(a)	Second issuance of 7,486,209 units.


(b)	First issuance of 15,760,441 units.

Series D Preferred Units Conversion and Redemption Features

At any time on or after June 29, 2020, each holder of Series D Preferred Units may convert all or any portion of its Series D Preferred Units into common units on a one-for-one basis (plus any unpaid Series D distributions), subject to anti-dilution adjustments, at any time, but not more than once per quarter, so long as any conversion is for at least $50.0 million based on the Series D Preferred Unit Purchase Price (or such lesser amount representing all of a holder’s Series D Preferred Units).

The Partnership may redeem all or any portion of the Series D Preferred Units, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit at any time on or after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit at any time on or after June 29, 2025; plus, in each case, the sum of any unpaid distributions on the applicable Series D Preferred Unit plus the distributions prorated for the number of days elapsed (not to exceed 90) in the period of redemption (Series D Partial Period Distributions). The holders have the option to convert the units prior to such redemption as discussed above.

Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to require the Partnership to redeem all of the Series D Preferred Units held by such holder at a redemption price equal to $29.19 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, the Partnership may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.

Series D Preferred Units Change of Control

Upon certain events involving a change of control, each holder of the Series D Preferred Units may elect to: (i) convert its Series D Preferred Units into common units on a one-for-one basis, plus any unpaid Series D distributions; (ii) require the Partnership to redeem its Series D Preferred Units for an amount equal to the sum of (a) $29.82 per Series D Preferred Unit plus (b) any unpaid Series D distributions plus (c) the applicable distribution amount for the distribution periods ending after the change of control event and prior to (but including) the fourth anniversary of the Initial Closing; (iii) if the Partnership is the surviving entity and its common units continue to be listed, continue to hold its Series D Preferred Units; or (iv) if the Partnership will not be the surviving entity, or it will be the surviving entity but its common units will cease to be listed, require the Partnership to use its commercially reasonable efforts to deliver a security in the surviving entity that has substantially similar terms as the Series D Preferred Units; however, if the Partnership is unable to deliver a mirror security, each holder is still entitled to option (i) or (ii) above.

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Registration Rights Agreement

On June 29, 2018, in connection with the Initial Closing and pursuant to the Series D Preferred Unit Purchase Agreement, the Partnership entered into a Registration Rights Agreement (the Registration Rights Agreement) with the Purchasers relating to the registration of the Series D Preferred Units and common units issuable upon conversion of the Series D Preferred Units (the Common Unit Registrable Securities, and, collectively with the Series D Preferred Units, the Registrable Securities). Pursuant to the Registration Rights Agreement, the Partnership is required to use its commercially reasonable efforts to file a registration statement and to cause such registration statement to become effective: (i) with respect to the Common Unit Registrable Securities, no later than one year after the Initial Closing; and (ii) with respect to the Series D Preferred Units, after the second anniversary of the Initial Closing, no later than one year after receipt by the Partnership of a written request from holders holding a majority of the Series D Preferred Units to register the Series D Preferred Units. If the Partnership fails to cause such registration statements to become effective by such dates, the Partnership will be required to pay certain amounts to the holders of the Registrable Securities as liquidated damages.

Series D Preferred Units Accounting Treatment

The Series D Preferred Units include redemption provisions at the option of the holders of the Series D Preferred Units and upon a Series D Change of Control (as defined in the partnership agreement), which are outside the Partnership’s control. Therefore, the Series D Preferred Units are presented in the mezzanine section of the consolidated balance sheets. The Series D Preferred Units have been recorded at their issuance date fair value, net of issuance costs. We reassess the presentation of the Series D Preferred Units in our consolidated balance sheets on a quarterly basis.

The Series D Preferred Units are subject to accretion from their carrying value at the issuance date to the redemption value, which is based on the redemption right of the Series D Preferred Unit holders that may be exercised at any time on or after June 29, 2028, using the effective interest method over a period of ten years. In the calculation of net income per unit, the accretion is treated in the same manner as a distribution and deducted from net income to arrive at net income attributable to common units.

20. PARTNERS’ EQUITY

Please refer to Note 4 for a discussion of the Merger.

Partnership Agreement Amendments

In the third quarter of 2018, NuStar Energy’s partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. The partnership agreement was also amended and restated in the second quarter of 2018 in connection with the issuance of our Series D Preferred Units discussed in Note 19. In 2017, the partnership agreement was amended and restated in connection with the issuances of our Series B Preferred Units and Series C Preferred Units described below, and in connection with the Navigator Acquisition to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Acquisition Agreement, starting with the distributions for the second quarter of 2017.

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Series A, B and C Preferred Units

The following is a summary of our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively the Series A, B and C Preferred Units) issued and outstanding as of December 31, 2018:



Units	Original Issuance Date	Number of Units Issued and Outstanding	Price per Unit		Net Proceeds (in millions)		Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit)		Fixed Distribution Rate per Unit per Annum		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units	November 25, 2016	9,060,000	$	25.00	$	218.4	8.50	%	$	2.125	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	April 28, 2017	15,400,000	$	25.00	$	371.8	7.625	%	$	1.90625	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	November 30, 2017	6,900,000	$	25.00	$	166.7	9.00	%	$	2.25	December 15, 2022	Three-month LIBOR plus 6.88%

We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, those preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicable conversion rate. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.

The following table summarizes financial information related to our Series A, B and C Preferred Units:



	Preferred Limited Partners
	Series A			Series B			Series C			Total
	(Thousands of Dollars)
Balance as of January 1, 2016	$	—		$	—		$	—		$	—
Issuance of units	218,400			—			—			218,400
Net income	1,925			—			—			1,925
Distributions to partners	(1,925		)	—			—			(1,925		)
Balance as of December 31, 2016	218,400			—			—			218,400
Issuance of units	—			371,823			166,737			538,560
Net income	19,253			19,815			1,380			40,448
Distributions to partners	(19,253		)	(19,815		)	(1,380		)	(40,448		)
Other	(93		)	(189		)	(75		)	(357		)
Balance as of December 31, 2017	218,307			371,634			166,662			756,603
Net income	19,253			29,357			15,481			64,091
Distributions to partners	(19,253		)	(29,357		)	(15,481		)	(64,091		)
Other	—			(158		)	(144		)	(302		)
Balance as of December 31, 2018	$	218,307		$	371,476		$	166,518		$	756,301

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Distributions on the Series A, B and C Preferred Units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Series A, B and C Preferred Units rank equal to each other and to the Series D Preferred Units, and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation. The following table summarizes information about cash distributions declared for our Series A, B and C Preferred Units:



	Cash Distributions Per Unit
Period	Series A		Series B		Series C
December 15, 2018 - March 14, 2019	$	0.53125	$	0.47657	$	0.56250
September 15, 2018 - December 14, 2018	$	0.53125	$	0.47657	$	0.56250
June 15, 2018 - September 14, 2018	$	0.53125	$	0.47657	$	0.56250
March 15, 2018 - June 14, 2018	$	0.53125	$	0.47657	$	0.56250
December 15, 2017 - March 14, 2018	$	0.53125	$	0.47657	N/A
November 30, 2017 - March 14, 2018	N/A		N/A		$	0.65625

Common Units and General Partner

Issuances of Common Units. As a result of the Merger discussed in Note 4, we issued approximately 13.4 million incremental NuStar Energy common units in the third quarter of 2018, in exchange for the previously outstanding NSH units.

In the second quarter of 2018, we issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC. We used the proceeds of $10.2 million from the sale of these units, including a contribution of $0.2 million from our general partner to maintain the 2% general partner economic interest it owned at that time, for general partnership purposes.

For the years ended December 31, 2018, 2017 and 2016, we issued 225,144, 185,455 and 135,100 common units, respectively, in connection with the vestings of awards issued under our long-term incentive plans.

Cash Distributions. We make quarterly distributions to common unitholders, and, prior to the Merger, made quarterly distributions to the general partner of 100% of our “Available Cash,” generally defined as cash receipts less cash disbursements, including distributions to our preferred units, and cash reserves established by the general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The common unitholders receive a distribution each quarter as determined by the board of directors, subject to limitation by the distributions in arrears, if any, on our preferred units. Prior to the Merger, our Available Cash was distributed based on the percentages shown below:



	Percentage of Distribution
Quarterly Distribution Amount Per Common Unit	Common Unitholders	General Partner Including Incentive Distributions
Up to $0.60	98%	2%
Above $0.60 up to $0.66	90%	10%
Above $0.66	75%	25%

Because the Merger was effective prior to the record date for the distribution for the second quarter of 2018, the general partner received no distributions after the first quarter distribution. Beginning with the second quarter of 2018, the common limited partners’ distribution includes the additional common units issued in exchange for previously outstanding NSH units because the Merger closed prior to the common unit distribution record date for the second quarter of 2018.

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The following table reflects the allocation of total cash distributions to the general partner and common limited partners applicable to the period in which the distributions were earned:



	Year Ended December 31,
	2018		2017		2016
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	1,141	$	9,252	$	7,877
General partner incentive distribution	—		45,669		43,407
Total general partner distribution	1,141		54,921		51,284
Common limited partners’ distribution	248,705		407,681		342,598
Total cash distributions	$	249,846	$	462,602	$	393,882

Cash distributions per unit applicable to common limited partners	$	2.40	$	4.38	$	4.38

The following table summarizes information about quarterly cash distributions declared for our common limited partners, and prior to the Merger, our general partner:



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 31, 2018	$	0.60	$	64,336	February 8, 2019	February 13, 2019
September 30, 2018	$	0.60	$	64,248	November 8, 2018	November 14, 2018
June 30, 2018	$	0.60	$	64,205	August 7, 2018	August 13, 2018
March 31, 2018	$	0.60	$	57,057	May 8, 2018	May 14, 2018

Net Income Applicable to the General Partner. For the year ended December 31, 2018, net income applicable to the general partner totaled $2.5 million and related to the general partner interest allocation prior to the Merger. The following table details the calculation of net income applicable to the general partner for 2017 and 2016:



	Year Ended December 31,
	2017			2016
	(Thousands of Dollars)
Net income attributable to NuStar Energy L.P.	$	147,964		$	150,003
Less preferred limited partner interest	40,448			1,925
Less general partner incentive distribution	45,669			43,407
Net income after general partner incentive distribution and preferred limited partner interest	61,847			104,671
General partner interest allocation	2		%	2		%
General partner interest allocation of net income	1,237			2,091
General partner incentive distribution	45,669			43,407
Net income applicable to general partner	$	46,906		$	45,498

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Accumulated Other Comprehensive Income (Loss)

The balance of and changes in the components included in AOCI were as follows:



	Foreign Currency Translation			Cash Flow Hedges			Pension and Other Postretirement Benefits			Total
	(Thousands of Dollars)
Balance as of January 1, 2016	$	(60,826	)	$	(27,968	)	$	—		$	(88,794	)
Employee Transfer	—			—			4,201			4,201
Deferred income tax adjustments	—			—			2,414			2,414
Other comprehensive loss before reclassification adjustments	(8,243		)	(2,621		)	(7,852		)	(18,716		)
Net gain on pension costs reclassified into operating expense	—			—			(1,200		)	(1,200		)
Net gain on pension costs reclassified into general and administrative expense	—			—			(413		)	(413		)
Net loss on cash flow hedges reclassified into interest expense, net	—			8,331			—			8,331
Other comprehensive (loss) income	(8,243		)	5,710			(2,850		)	(5,383		)
Balance as of December 31, 2016	(69,069		)	(22,258		)	(2,850		)	(94,177		)
Other comprehensive income (loss) before reclassification adjustments	17,466			(8,670		)	(4,641		)	4,155
Net gain on pension costs reclassified into operating expense	—			—			(1,143		)	(1,143		)
Net gain on pension costs reclassified into general and administrative expense	—			—			(386		)	(386		)
Net loss on cash flow hedges reclassified into interest expense, net	—			6,624			—			6,624
Other comprehensive income (loss)	17,466			(2,046		)	(6,170		)	9,250
Balance as of December 31, 2017	(51,603		)	(24,304		)	(9,020		)	(84,927		)
Other comprehensive income before reclassification adjustments	(13,880		)	17,912			3,282			7,314
Sale of European operations reclassified into other income, net	18,124			—			—			18,124
Net gain on pension costs reclassified into other income, net	—			—			(814		)	(814		)
Net loss on cash flow hedges reclassified into interest expense, net	—			5,499			—			5,499
Other	60			—			(134		)	(74		)
Other comprehensive income	4,304			23,411			2,334			30,049
Balance as of December 31, 2018	$	(47,299	)	$	(893	)	$	(6,686	)	$	(54,878	)

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21. NET (LOSS) INCOME PER COMMON UNIT

As discussed in Note 19, the Series D Preferred Units are convertible into common units at the option of the holder at any time on or after June 29, 2028. As such, we calculated the dilutive effect of the Series D Preferred Units using the if-converted method. For the year ended December 31, 2018, the effect of the assumed conversion of the 23,246,650 Series D Preferred Units outstanding as of December 31, 2018 was antidilutive; therefore, we did not include such conversion in the computation of diluted net (loss) income per common unit.

The following table details the calculation of net (loss) income per common unit:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars, Except Unit and Per Unit Data)
Net income	$	205,794		$	147,964		$	150,003
Distributions to preferred limited partners	(92,540		)	(40,448		)	(1,925		)
Distributions to general partner (including incentive distribution rights)	(1,141		)	(54,921		)	(51,284		)
Distributions to common limited partners	(248,705		)	(407,681		)	(342,598		)
Distribution equivalent rights to restricted units	(2,045		)	(2,965		)	(2,697		)
Distributions in excess of earnings	$	(138,637	)	$	(358,051	)	$	(248,501	)

Distributions to common limited partners	$	248,705		$	407,681		$	342,598
Allocation of distributions in excess of earnings	(138,659		)	(350,890		)	(243,530		)
Series D Preferred Unit accretion (refer to Note 19)	(8,195		)	—			—
Loss to common unitholders attributable to the Merger (refer to Note 4)	(377,079		)	—			—
Net (loss) income attributable to common units:	$	(275,228	)	$	56,791		$	99,068

Basic weighted-average common units outstanding	99,490,495			88,825,964			78,080,484

Diluted common units outstanding:
Basic weighted-average common units outstanding	99,490,495			88,825,964			78,080,484
Effect of dilutive potential common units	40,677			—			32,518
Diluted weighted-average common units outstanding	99,531,172			88,825,964			78,113,002

Basic and diluted net (loss) income per common unit	$	(2.77	)	$	0.64		$	1.27

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22. STATEMENTS OF CASH FLOWS

Changes in current assets and current liabilities were as follows:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	22,482		$	(865	)	$	(23,234	)
Receivable from related parties	160			112			(317		)
Inventories	3,819			11,936			940
Prepaid and other current assets	3,694			3,393			8,128
Increase (decrease) in current liabilities:
Accounts payable	8,003			(30,409		)	14,071
Payable to related party	—			—			894
Accrued interest payable	(4,279		)	6,489			(256		)
Accrued liabilities	39,577			(11,157		)	161
Taxes other than income tax	4,521			(3,529		)	2,690
Income tax payable	285			(2,463		)	639
Changes in current assets and current liabilities	$	78,262		$	(26,493	)	$	3,716

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:


•	current assets and current liabilities acquired and disposed of during the period;


•	the change in the amount accrued for capital expenditures;


•	the effect of foreign currency translation;


•	reclassification of the Axeon Term Loan to other current assets from other long-term assets, net in 2016;


•	changes in the fair values of our interest rate swap agreements; and


•	non-cash related party transactions associated with the Employee Transfer.

Cash flows related to interest and income taxes were as follows:



	Year Ended December 31,
	2018		2017		2016
	(Thousands of Dollars)
Cash paid for interest, net of amount capitalized	$	183,078	$	158,089	$	142,663
Cash paid for income taxes, net of tax refunds received	$	8,535	$	11,338	$	11,847

23. EMPLOYEE BENEFIT PLANS

Employee Transfer

Prior to the Employee Transfer discussed in Note 1, we reimbursed all costs incurred by NuStar GP, LLC related to the pension plans and other postretirement benefit plans at cost. For comparability purposes this footnote presents information related to these benefit plans on a combined basis for periods during 2016 prior to the Employee Transfer and after the Employee Transfer, including the components of net periodic benefit cost (income) and adjustments to other comprehensive income (loss). Consequently, certain amounts presented below will differ from amounts reflected in our consolidated financial statements. See Note 4 for additional discussion on the Employee Transfer.

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Thrift Plans

The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to the Thrift Plan for the years ended December 31, 2018, 2017 and 2016 totaled $7.4 million, $6.9 million and $6.6 million, respectively.

The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.

We also maintain other defined contribution plans for certain international employees located in Canada and the Caribbean Netherlands. We also maintained plans for international employees in the United Kingdom and Netherlands prior to the sale of our European operations on November 30, 2018. For the years ended December 31, 2018, 2017 and 2016, our costs for these plans totaled $2.5 million, $2.5 million and $2.4 million, respectively.

Pension and Other Postretirement Benefits

The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits are determined based on age, years of vesting service and interest credits, and employees become fully vested in their benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash balance formula or a final average pay formula (FAP). Effective January 1, 2014, the Pension Plan was amended to freeze the FAP benefits as of December 31, 2013, and going forward, all eligible employees are covered under the cash balance formula discussed above.

We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a funded plan subject to the Employee Retirement Income Security Act.

The Pension Plan and Excess Pension Plan are collectively referred to as the Pension Plans in the tables and discussion below. Our other postretirement benefit plans include a contributory medical benefits plan for U.S. employees who retired prior to April 1, 2014 and, for employees who retire on or after April 1, 2014, a partial reimbursement for eligible third-party health care premiums. We use December 31 as the measurement date for our pension and other postretirement plans.

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The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended December 31, 2018 and 2017 were as follows:



	Pension Plans						Other Postretirement Benefit Plans
	2018			2017			2018			2017
	(Thousands of Dollars)
Change in benefit obligation:
Benefit obligation, January 1	$	149,817		$	127,402		$	12,410		$	11,061
Service cost	9,621			8,955			504			456
Interest cost	4,824			4,507			429			430
Benefits paid	(7,929		)	(5,941		)	(255		)	(342		)
Participant contributions	—			—			87			215
Actuarial (gain) loss	(14,500		)	14,894			(2,267		)	590
Benefit obligation, December 31	$	141,833		$	149,817		$	10,908		$	12,410
Change in plan assets:
Plan assets at fair value, January 1	$	129,878		$	107,644		$	—		$	—
Actual return on plan assets	(6,034		)	17,070			—			—
Employer contributions	11,034			11,105			168			127
Benefits paid	(7,929		)	(5,941		)	(255		)	(342		)
Participant contributions	—			—			87			215
Plan assets at fair value, December 31	$	126,949		$	129,878		$	—		$	—
Reconciliation of funded status:
Fair value of plan assets at December 31	$	126,949		$	129,878		$	—		$	—
Less: Benefit obligation at December 31	141,833			149,817			10,908			12,410
Funded status at December 31	$	(14,884	)	$	(19,939	)	$	(10,908	)	$	(12,410	)
Amounts recognized in the consolidated balance sheets (a):
Accrued liabilities	$	(267	)	$	(210	)	$	(362	)	$	(376	)
Other long-term liabilities	(14,617		)	(19,729		)	(10,546		)	(12,034		)
Net pension liability	$	(14,884	)	$	(19,939	)	$	(10,908	)	$	(12,410	)


(a)	For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.

The accumulated benefit obligation is the present value of benefits earned to date, assuming no future salary increases. The aggregate accumulated benefit obligation for our Pension Plans as of December 31, 2018 and 2017 was $139.7 million and $146.3 million, respectively. As of December 31, 2018 and 2017, the aggregate accumulated benefit obligation for the Pension Plans exceeded plan assets.

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The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows:



	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
	(Thousands of Dollars)
Service cost	$	9,621		$	8,955		$	7,703		$	504		$	456		$	419
Interest cost	4,824			4,507			4,023			429			430			401
Expected return on plan assets	(7,417		)	(6,411		)	(5,407		)	—			—			—
Amortization of prior service credit	(2,057		)	(2,059		)	(2,063		)	(1,145		)	(1,145		)	(1,145		)
Amortization of net actuarial loss	2,174			1,484			1,091			214			191			181
Net periodic benefit cost (income)	$	7,145		$	6,476		$	5,347		$	2		$	(68	)	$	(144	)

We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service credit” in table above). We amortize the actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net actuarial loss” in table above).

Adjustments to other comprehensive income (loss) related to our Pension Plans and other postretirement benefit plans were as follows:



	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
	(Thousands of Dollars)
Net unrecognized gain (loss) arising during the year:
Net actuarial gain (loss)	$	1,049		$	(4,235	)	$	(7,544	)	$	2,267		$	(590	)	$	(368	)
Net (gain) loss reclassified into income:
Amortization of prior service credit	(2,057		)	(2,059		)	(2,063		)	(1,145		)	(1,145		)	(1,145		)
Amortization of net actuarial loss	2,174			1,484			1,091			214			191			181
Net loss (gain) reclassified into income	117			(575		)	(972		)	(931		)	(954		)	(964		)

Reclassification of stranded tax effects	(74		)	—			—			—			—			—
Income tax (expense) benefit	(69		)	162			57			(25		)	22			3
Total changes to other comprehensive income (loss)	$	1,023		$	(4,648	)	$	(8,459	)	$	1,311		$	(1,522	)	$	(1,329	)

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The amounts recorded as a component of “Accumulated other comprehensive loss” on the consolidated balance sheets related to our Pension Plans and other postretirement benefit plans were as follows:



	Pension Plans						Other Postretirement Benefit Plans
	December 31,						December 31,
	2018			2017			2018			2017
	(Thousands of Dollars)
Unrecognized actuarial loss	$	(27,955	)	$	(31,178	)	$	(1,673	)	$	(4,154	)
Prior service credit	14,547			16,604			8,319			9,464
Deferred tax asset	76			219			—			25
Accumulated other comprehensive (loss) income, net of tax	$	(13,332	)	$	(14,355	)	$	6,646		$	5,335

The following pre-tax amounts in accumulated other comprehensive loss as of December 31, 2018 are expected to be recognized as components of net periodic benefit cost (income) in 2019:



	Pension Plans			Other Postretirement Benefit Plans
	(Thousands of Dollars)
Actuarial loss	$	846		$	42
Prior service credit	$	(2,057	)	$	(1,145	)

Investment Policies and Strategies

The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year. Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual basis. As of December 31, 2018, the target allocations for plan assets are 65% equity securities and 35% fixed income investments, with certain fluctuations permitted.

The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.

Fair Value of Plan Assets

We disclose the fair value for each major class of plan assets in the Pension Plan into three levels: Level 1, defined as observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which little or no market data exists.

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The major classes of plan assets measured at fair value for the Pension Plan were as follows:



	December 31, 2018
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	608	$	—	$	—	$	608
Equity securities:
U.S. large cap equity fund (a)	—		70,525		—		70,525
International stock index fund (b)	13,391		—		—		13,391
Fixed income securities:
Bond market index fund (c)	42,425		—		—		42,425
Total	$	56,424	$	70,525	$	—	$	126,949



	December 31, 2017
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	381	$	—	$	—	$	381
Equity securities:
U.S. large cap equity fund (a)	—		75,353		—		75,353
International stock index fund (b)	14,480		—		—		14,480
Fixed income securities:
Bond market index fund (c)	39,664		—		—		39,664
Total	$	54,525	$	75,353	$	—	$	129,878


(a)	This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.


(b)	This fund tracks the performance of the Total International Composite Index.


(c)	This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.

Contributions to the Pension Plans

For the year ended December 31, 2018, we contributed $11.0 million and $0.2 million to the Pension Plans and other postretirement benefit plans, respectively. During 2019, we expect to contribute approximately $11.3 million and $0.3 million to the Pension Plans and other postretirement benefit plans, respectively, which principally represent contributions either required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years ending December 31:



	Pension Plans		Other Postretirement Benefit Plans
	(Thousands of Dollars)
2019	$	9,454	$	362
2020	$	10,309	$	390
2021	$	11,072	$	423
2022	$	11,593	$	475
2023	$	12,274	$	503
Years 2024-2028	$	68,198	$	3,200

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Assumptions

The weighted-average assumptions used to determine the benefit obligations were as follows:



	Pension Plans				Other Postretirement Benefit Plans
	December 31,				December 31,
	2018		2017		2018		2017
Discount rate	4.40	%	3.72	%	4.53	%	3.82	%
Rate of compensation increase	3.51	%	3.51	%	n/a		n/a

The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:



	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2018		2017		2016
Discount rate	3.72	%	4.33	%	4.61	%	3.82	%	4.49	%	4.75	%
Expected long-term rate of return on plan assets	6.50	%	6.00	%	6.25	%	n/a		n/a		n/a
Rate of compensation increase	3.51	%	3.51	%	3.51	%	n/a		n/a		n/a

The assumed health care cost trend rates were as follows:



	December 31,
	2018		2017
Health care cost trend rate assumed for next year	6.84	%	6.84	%
Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2028		2028

We sponsor a contributory postretirement health care plan for employees who retired prior to April 1, 2014. The plan has an annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in employer’s cost is 2.5% per year. The assumed increase in total health care cost exceeds the 2.5% indexed cap, so increasing or decreasing the health care cost trend rate by 1% does not materially change our obligation or expense for the postretirement health care plan.

24. UNIT-BASED COMPENSATION

Overview

2000 LTIP. We sponsor the 2000 LTIP, which provides for the right to issue and award up to 3,250,000 of our common units to employees and non-employee directors (NEDs). Awards available under the 2000 LTIP include restricted units, performance units, unit options, unit awards and distribution equivalent rights (DERs). DERs entitle the participant to receive cash equal to cash distributions made on any award prior to its vesting. As of December 31, 2018, a total of 655,848 common units remained available to be awarded under the 2000 LTIP.

Prior to the Employee Transfer, NuStar GP, LLC sponsored the 2000 LTIP, and we reimbursed NuStar GP, LLC for awards under this plan. Most of our currently outstanding awards are classified as equity awards as we intend to settle these awards through the issuance of our common units. Effective March 1, 2016, we assumed sponsorship of the 2000 LTIP and assumed all outstanding awards under the 2000 LTIP. The transfer of the outstanding awards qualified as a plan modification. Therefore, we measured the fair value of the outstanding awards based on the common unit price on the transfer date. Please refer to Note 4 for a discussion of our related party agreements.

2006 LTIP. Effective July 20, 2018 and in conjunction with the Merger, we assumed the 2006 Long-Term Incentive Plan (the 2006 LTIP). Prior to the Merger, NuStar GP Holdings sponsored the 2006 LTIP, pursuant to which it could award up to 2,000,000 NSH units to its employees and NEDs. At the effective time of the Merger, each outstanding award of NuStar GP

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Holdings restricted units was converted, on the same terms and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy restricted units subject to the converted awards was determined pursuant to the 0.55 exchange ratio provided in the Merger Agreement. The NSH units remaining available to be awarded under the 2006 LTIP were also converted pursuant to the exchange ratio provided in the Merger Agreement. Awards available under the 2006 LTIP include restricted units, performance units, unit options, unit awards and DERs. As of December 31, 2018, a total of 219,632 NS units remained available to be awarded under the 2006 LTIP.

The following table summarizes information pertaining to both long-term incentive plans:



	Units Outstanding December 31,			Compensation Expense Year Ended December 31,
	2018	2017	2016	2018		2017		2016
				(Thousands of Dollars)
Restricted Units:
Domestic employees	1,028,484	736,746	647,340	$	8,233	$	7,881	$	5,980
Non-employee directors (NEDs)	59,752	27,097	18,134	524		251		388
International employees	30,918	58,107	50,609	1,158		595		715
Performance Units	158,326	80,961	77,014	1,889		—		1,211
Unit Awards	—	—	—	1,358		—		—
Total	1,277,480	902,911	793,097	$	13,162	$	8,727	$	8,294

Restricted Units

Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting. We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of the common units at the grant date (for domestic employees) or the fair value of the common units measured at each reporting period (for NEDs and international employees). DERs paid with respect to outstanding equity-classified unvested restricted units reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified unvested restricted units are expensed. In connection with the DERs for equity awards, we paid $2.0 million and $3.0 million, respectively, in cash, for the years ended December 31, 2018 and 2017.

Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally vest over five years, beginning one year after the grant date. The fair value of these awards is measured at the grant date (or transfer date for issuances prior to the Employee Transfer).

Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of these awards is equal to the market price of our common units at each reporting period.

International Employees. The outstanding restricted units granted to international employees are cash-settled and accounted for as liability-classified awards. These awards vest over three to five years and the fair value is equal to the market price of our common units at each reporting period.

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A summary of our restricted unit activity is as follows:



	Domestic Employees
	Number of Restricted Units		Weighted- Average Grant-Date Fair Value Per Unit		Number of Restricted Units to NEDs		Number of Restricted Units to International Employees
Nonvested units as of January 1, 2016	—		$	—	—		—
Transferred on March 1, 2016	586,524		35.03		17,629		49,121
Granted	246,070		47.70		8,730		20,107
Vested	(180,724	)	35.50		(8,225	)	(14,812	)
Forfeited	(4,530	)	35.03		—		(3,807	)
Nonvested units as of December 31, 2016	647,340		39.72		18,134		50,609
Granted	307,009		29.56		17,110		24,533
Vested	(201,466	)	38.74		(8,147	)	(16,440	)
Forfeited	(16,137	)	40.00		—		(595	)
Nonvested units as of December 31, 2017	736,746		35.95		27,097		58,107
Converted on July 20, 2018	53,447		24.99		18,915		—
Granted	518,282		24.07		34,303		16,197
Vested	(235,746	)	35.12		(20,563	)	(41,406	)
Forfeited	(44,245	)	36.05		—		(1,980	)
Nonvested units as of December 31, 2018	1,028,484		$	29.47	59,752		30,918

The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2018, 2017 and 2016 was $7.5 million, $6.5 million and $9.0 million, respectively. We issued 189,399 common units in connection with these award vestings, net of employee tax withholding requirements, for the year ended December 31, 2018. Unrecognized compensation cost related to our equity-classified employee awards totaled $29.2 million as of December 31, 2018, which we expect to recognize over a weighted-average period of 3.8 years.

Performance Units

Performance units are issued to certain of our key employees and represent rights to receive our common units upon achieving a performance measure for the performance period. The performance measure is determined each year by the NuStar GP, LLC Compensation Committee for the following year. Achievement of the performance measure determines the rate at which the performance units convert into our common units, which ranges from zero to 200% for certain awards.

Performance units awarded vest in three annual increments (tranches), based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each applicable year. Therefore, the performance units are not considered granted for accounting purposes until the Compensation Committee has set the performance measure for each tranche of awards. Performance units are equity-classified awards measured at the grant date fair value. In addition, since the performance units granted do not receive DERs, the grant date fair value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting period. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is probable that the specified performance measure will be achieved. Additionally, changes in the actual or estimated outcomes that affect the quantity of performance units expected to be converted are recognized as a cumulative adjustment.

For the period from the Employee Transfer date to December 31, 2016, no performance units vested or were granted or forfeited. For the year ended December 31, 2017, we issued 33,438 common units in connection with the performance award vestings related to 2016 performance, net of employee tax withholding requirements, and the total fair value of performance awards vested was $2.9 million. For the year ended December 31, 2018, no performance units vested with respect to 2017 performance.

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A summary of our performance units is shown below:



			Granted for Accounting Purposes
	Total Performance Units Awarded		Performance Units		Weighted-Average Grant Date Fair Value per Unit
Outstanding as of January 1, 2017	77,014		35,373		$	31.75
Granted	39,320		38,865		50.04
Additional grant upon conversion (related to 2016 performance)	17,690		17,690		31.75
Vested (related to 2016 performance)	(53,063	)	(53,063	)	31.75
Outstanding as of December 31, 2017	80,961		38,865		$	50.04
Granted	116,230		80,690		$	23.43
Vested	—		—		—
Forfeitures	(38,865	)	(38,865	)	$	50.04
Outstanding as of December 31, 2018	158,326		80,690		23.43

Unit Awards

Unit awards are equity-classified awards of fully vested common units. We record compensation expense based on the fair value of the common units at the grant date. For the year ended December 31, 2018, we granted 55,133 unit awards at a grant date fair value of $24.63 per unit, resulting in the issuance of 35,745 common units, net of employee tax withholding requirements.

25. INCOME TAXES

Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:



	Year Ended December 31,
	2018		2017			2016
	(Thousands of Dollars)
Current:
U.S.	$	4,515	$	3,117		$	2,280
Foreign	4,658		6,335			6,329
Foreign withholding tax	192		479			3,833
Total current	9,365		9,931			12,442

Deferred:
U.S.	1,403		1,468			2,680
Foreign	394		(1,065		)	(1,122		)
Foreign withholding tax	246		(397		)	(2,027		)
Total deferred	2,043		6			(469		)

Total income tax expense	$	11,408	$	9,937		$	11,973

The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by applying the statutory federal income tax rate (21% for 2018 and 35% for 2017 and 2016) to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries expected to be repatriated.

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The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:



	December 31,
	2018			2017
	(Thousands of Dollars)
Deferred income tax assets:
Net operating losses	$	21,009		$	20,688
Employee benefits	362			483
Environmental and legal reserves	239			185
Allowance for bad debt	1,970			1,982
Other	1,796			2,050
Total deferred income tax assets	25,376			25,388
Less: Valuation allowance	(12,442		)	(11,251		)
Net deferred income tax assets	12,934			14,137

Deferred income tax liabilities:
Property, plant and equipment	(25,128		)	(36,176		)
Foreign withholding tax	(234		)	—
Total deferred income tax liabilities	(25,362		)	(36,176		)

Net deferred income tax liability	$	(12,428	)	$	(22,039	)

Reported on the consolidated balance sheets as:
Deferred income tax asset	$	—		$	233
Deferred income tax liability	(12,428		)	(22,272		)
Net deferred income tax liability	$	(12,428	)	$	(22,039	)

As of December 31, 2018, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $86.8 million and $9.3 million, respectively, which are subject to various limitations on use and expire in years 2025 through 2037 for U.S. losses and in years 2019 through 2028 for foreign losses, except U.S. losses generated in 2018 can be carried forward indefinitely.

As of December 31, 2018 and 2017, we recorded a valuation allowance of $12.4 million and $11.3 million, respectively, related to our deferred tax assets. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In 2018, there was a $0.9 million increase in the valuation allowance for the U.S. net operating loss and a $0.2 million increase in the foreign net operating loss valuation allowance due to changes in our estimates of the amount of those loss carryforwards that will be realized, based upon future taxable income.

The realization of net deferred income tax assets recorded as of December 31, 2018 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of December 31, 2018 will be realized, based on expected future taxable income.

Tax Reform Update

On December 22, 2017, the U.S. enacted the Act, commonly referred to as “U.S. tax reform.” The Act significantly changed U.S. corporate income tax laws by, among other things, reducing the U.S. corporate tax rate from 35% to 21%, starting in 2018, and creating a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of U.S. subsidiaries. As a result, we recorded an expense of $0.8 million in 2017 and a benefit of $0.3 million in 2018. The 2017 expense of $0.8 million, which is included in “Income tax expense” on the consolidated statements of income, consists of two components: (i) $0.7 million relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are wholly owned by one of our U.S. subsidiaries and (ii) $0.1 million resulting from the revaluation of our net deferred tax assets in the U.S. based on the new lower corporate income tax rate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Although the $0.8 million expense represented what we believed to be a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it was provisional. In the fourth quarter of 2018, we finalized our assessment of the two components comprising the 2017 provisional expense and recognized a benefit of $0.3 million in “Income tax expense” on the consolidated statements of income relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are wholly owned by one of our U.S. subsidiaries. No other adjustments to the provisional amounts were deemed necessary.

Due to the complexity of the new Global Intangible Low-Tax Income (GILTI) tax rules, in 2018 we continued to evaluate this provision of the Act and the application of FASB’s Accounting Standards Codification 740. Under GAAP, we are allowed to make an accounting policy choice of either (i) treating taxes due on future U.S. inclusions in taxable income related to GILTI as a current-period expense when incurred (the period cost method) or (ii) factoring such amounts into a company’s measurement of its deferred taxes (the deferred method). Our selection of an accounting policy with respect to the new GILTI tax rules are based, in part, on our analysis of our global income to determine whether we expect to have future U.S. inclusions in taxable income related to GILTI and, if so, what the impact is expected to be. We will treat the taxes due on future U.S. inclusions in taxable income related to GILTI as a current-period expense when incurred (the period cost method). The income tax effect of GILTI, reported as a component of “Income tax expense” on the consolidated statements of income for the year ended December 31, 2018, is $0.1 million.

Under GAAP, the Base Erosion Anti-Abuse Tax (BEAT) provisions are designed to be an “incremental tax,” so BEAT is treated as a current-period expense when incurred (the period cost method). We have determined that no adjustments related to BEAT are necessary in our consolidated financial statements.

26. SEGMENT INFORMATION

Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent strategic business units that offer different services and products. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. Our operations include the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Intersegment revenues result from storage agreements with wholly owned subsidiaries of NuStar Energy at rates consistent with the rates charged to third parties for storage.

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Results of operations for the reportable segments were as follows:



	Year Ended December 31,
	2018			2017			2016
	(Thousands of Dollars)
Revenues:
Pipeline	$	611,065		$	516,288		$	485,650
Storage:
Third parties	598,380			604,847			589,098
Intersegment	7,570			12,106			20,944
Total storage	605,950			616,953			610,042
Fuels marketing	752,312			692,884			681,934
Consolidation and intersegment eliminations	(7,570		)	(12,106		)	(20,944		)
Total revenues	$	1,961,757		$	1,814,019		$	1,756,682

Depreciation and amortization expense:
Pipeline	$	153,943		$	128,061		$	89,554
Storage	135,056			127,473			118,663
Total segment depreciation and amortization expense	288,999			255,534			208,217
Other depreciation and amortization expense	8,875			8,698			8,519
Total depreciation and amortization expense	$	297,874		$	264,232		$	216,736

Operating income:
Pipeline	$	272,695		$	231,795		$	248,238
Storage	181,471			219,439			214,801
Fuels marketing	24,440			5,983			3,406
Consolidation and intersegment eliminations	32			(1		)	—
Total segment operating income	478,638			457,216			466,445
General and administrative expenses	106,200			112,240			98,817
Other depreciation and amortization expense	8,875			8,698			8,519
Total operating income	$	363,563		$	336,278		$	359,109

Revenues by geographic area are shown in the table below:



	Year Ended December 31,
	2018		2017		2016
	(Thousands of Dollars)
United States	$	1,481,863	$	1,406,626	$	1,352,936
Netherlands	398,382		322,251		313,395
Other	81,512		85,142		90,351
Consolidated revenues	$	1,961,757	$	1,814,019	$	1,756,682

For the years ended December 31, 2018, 2017 and 2016, Valero Energy Corporation accounted for approximately 16%, or $309.8 million, 17%, or $300.0 million, and 18%, or $310.0 million, of our consolidated revenues, respectively. These revenues were included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated revenues.

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Total amounts of property, plant and equipment, net by geographic area were as follows:



	December 31,
	2018		2017
	(Thousands of Dollars)
United States	$	3,687,910	$	3,519,965
Netherlands	514,541		572,817
Other	86,171		208,151
Consolidated long-lived assets	$	4,288,622	$	4,300,933

Total assets by reportable segment were as follows:



	December 31,
	2018		2017
	(Thousands of Dollars)
Pipeline	$	3,637,226	$	3,492,417
Storage	2,424,342		2,735,563
Fuels marketing	112,906		118,746
Total segment assets	6,174,474		6,346,726
Other partnership assets	174,666		188,507
Total consolidated assets	$	6,349,140	$	6,535,233

Capital expenditures, including acquisitions, by reportable segment were as follows:



	Year Ended December 31,
	2018		2017		2016
	(Thousands of Dollars)
Pipeline	$	288,035	$	1,596,311	$	88,373
Storage	202,782		244,398		206,641
Other partnership assets	4,137		5,648		5,001
Total capital expenditures	$	494,954	$	1,846,357	$	300,015

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27. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

NuStar Energy has no operations, and its assets consist mainly of its 100% indirectly owned subsidiaries, NuStar Logistics and NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy and NuPOP. As a result, the following condensed consolidating financial statements are presented as an alternative to providing separate financial statements for NuStar Logistics and NuPOP.

Condensed Consolidating Balance Sheets

December 31, 2018

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	1,255	$	51	$	—	$	12,338	$	—		$	13,644
Receivables, net	—		2,212		—		146,096		—			148,308
Inventories	—		1,741		5,237		15,735		—			22,713
Prepaid and other current assets	61		14,422		908		2,102		—			17,493
Intercompany receivable	—		1,327,833		—		500,583		(1,828,416		)	—
Total current assets	1,316		1,346,259		6,145		676,854		(1,828,416		)	202,158
Property, plant and equipment, net	—		1,858,264		615,549		1,814,809		—			4,288,622
Intangible assets, net	—		49,107		—		683,949		—			733,056
Goodwill	—		149,453		170,652		716,871		—			1,036,976
Investment in wholly owned subsidiaries	3,355,636		1,750,256		1,425,283		857,485		(7,388,660		)	—
Other long-term assets, net	304		54,429		26,716		6,879		—			88,328
Total assets	$	3,357,256	$	5,207,768	$	2,244,345	$	4,756,847	$	(9,217,076	)	$	6,349,140
Liabilities, Mezzanine Equity and Partners’ Equity
Accounts payable	$	6,460	$	39,680	$	6,331	$	90,650	$	—		$	143,121
Short-term debt	—		18,500		—		—		—			18,500
Accrued interest payable	—		36,253		—		40		—			36,293
Accrued liabilities	1,280		24,858		8,082		67,773		—			101,993
Taxes other than income tax	125		7,285		4,718		6,955		—			19,083
Income tax payable	—		457		2		3,986		—			4,445
Intercompany payable	472,790		—		1,355,626		—		(1,828,416		)	—
Total current liabilities	480,655		127,033		1,374,759		169,404		(1,828,416		)	323,435
Long-term debt	—		3,050,531		—		61,465		—			3,111,996
Deferred income tax liability	—		1,675		9		10,744		—			12,428
Other long-term liabilities	—		28,392		12,348		38,818		—			79,558
Series D preferred units	563,992		—		—		—		—			563,992
Total partners’ equity	2,312,609		2,000,137		857,229		4,476,416		(7,388,660		)	2,257,731
Total liabilities, mezzanine equity and partners’ equity	$	3,357,256	$	5,207,768	$	2,244,345	$	4,756,847	$	(9,217,076	)	$	6,349,140

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Condensed Consolidating Balance Sheets

December 31, 2017

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	885	$	29	$	—	$	23,378	$	—		$	24,292
Receivables, net	—		280		—		176,495		—			176,775
Inventories	—		1,686		8,611		16,560		—			26,857
Prepaid and other current assets	61		11,412		4,191		6,844		—			22,508
Intercompany receivable	—		3,112,164		—		—		(3,112,164		)	—
Total current assets	946		3,125,571		12,802		223,277		(3,112,164		)	250,432
Property, plant and equipment, net	—		1,893,720		591,070		1,816,143		—			4,300,933
Intangible assets, net	—		58,530		—		725,949		—			784,479
Goodwill	—		149,453		170,652		777,370		—			1,097,475
Investment in wholly owned subsidiaries	2,891,371		24,162		1,301,717		790,882		(5,008,132		)	—
Deferred income tax asset	—		—		—		233		—			233
Other long-term assets, net	303		65,684		27,493		8,201		—			101,681
Total assets	$	2,892,620	$	5,317,120	$	2,103,734	$	4,342,055	$	(8,120,296	)	$	6,535,233
Liabilities and Partners’ Equity
Accounts payable	$	4,078	$	27,642	$	13,160	$	101,052	$	—		$	145,932
Short-term debt	—		35,000		—		—		—			35,000
Current portion of long-term debt	—		349,990		—		—		—			349,990
Accrued interest payable	—		40,402		—		47		—			40,449
Accrued liabilities	1,105		17,628		9,450		33,395		—			61,578
Taxes other than income tax	125		7,110		3,794		3,356		—			14,385
Income tax payable	—		732		4		3,436		—			4,172
Intercompany payable	322,296		—		1,277,691		1,512,177		(3,112,164		)	—
Total current liabilities	327,604		478,504		1,304,099		1,653,463		(3,112,164		)	651,506
Long-term debt, less current portion	—		3,201,220		—		61,849		—			3,263,069
Deferred income tax liability	—		1,262		12		20,998		—			22,272
Other long-term liabilities	—		58,806		8,861		50,630		—			118,297
Total partners’ equity	2,565,016		1,577,328		790,762		2,555,115		(5,008,132		)	2,480,089
Total liabilities and partners’ equity	$	2,892,620	$	5,317,120	$	2,103,734	$	4,342,055	$	(8,120,296	)	$	6,535,233

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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2018

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues	$	—		$	485,603		$	260,679		$	1,216,180	$	(705	)	$	1,961,757
Costs and expenses	2,407			317,286			163,667			1,115,539		(705		)	1,598,194
Operating (loss) income	(2,407		)	168,317			97,012			100,641		—			363,563
Equity in earnings of subsidiaries	207,973			17,167			121,913			212,249		(559,302		)	—
Interest income (expense), net	228			(191,835		)	(7,127		)	12,497		—			(186,237		)
Other income, net	—			3,876			446			35,554		—			39,876
Income (loss) before income tax expense (benefit)	205,794			(2,475		)	212,244			360,941		(559,302		)	217,202
Income tax expense (benefit)	—			588			(3		)	10,823		—			11,408
Net income (loss)	$	205,794		$	(3,063	)	$	212,247		$	350,118	$	(559,302	)	$	205,794

Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	496,454		$	221,125		$	1,097,458		$	(1,018	)	$	1,814,019
Costs and expenses	1,868			317,871			146,243			1,012,777			(1,018		)	1,477,741
Operating (loss) income	(1,868		)	178,583			74,882			84,681			—			336,278
Equity in earnings (loss) of subsidiaries	149,775			(10,616		)	89,405			158,700			(387,264		)	—
Interest income (expense), net	57			(176,897		)	(5,587		)	9,344			—			(173,083		)
Other income (expense), net	—			145			3			(5,442		)	—			(5,294		)
Income (loss) before income tax (benefit) expense	147,964			(8,785		)	158,703			247,283			(387,264		)	157,901
Income tax (benefit) expense	—			(820		)	2			10,755			—			9,937
Net income (loss)	$	147,964		$	(7,965	)	$	158,701		$	236,528		$	(387,264	)	$	147,964

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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	511,650		$	224,966		$	1,021,804		$	(1,738	)	$	1,756,682
Costs and expenses	1,806			302,099			150,384			945,022			(1,738		)	1,397,573
Operating (loss) income	(1,806		)	209,551			74,582			76,782			—			359,109
Equity in earnings (loss) of subsidiaries	151,794			(13,769		)	82,202			156,036			(376,263		)	—
Interest (expense) income, net	—			(139,827		)	(744		)	2,221			—			(138,350		)
Other income (expense), net	18			(58,264		)	(26		)	(511		)	—			(58,783		)
Income (loss) before income tax expense (benefit)	150,006			(2,309		)	156,014			234,528			(376,263		)	161,976
Income tax expense (benefit)	3			1,607			(23		)	10,386			—			11,973
Net income (loss)	$	150,003		$	(3,916	)	$	156,037		$	224,142		$	(376,263	)	$	150,003

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Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2018

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	205,794	$	(3,063	)	$	212,247	$	350,118	$	(559,302	)	$	205,794

Other comprehensive income:
Foreign currency translation adjustment	—		—			—		4,304		—			4,304
Net gain on pension and other postretirement benefit adjustments, net of tax expense	—		—			—		2,334		—			2,334
Net gain on cash flow hedges	—		23,411			—		—		—			23,411
Total other comprehensive income	—		23,411			—		6,638		—			30,049
Comprehensive income	$	205,794	$	20,348		$	212,247	$	356,756	$	(559,302	)	$	235,843

Condensed Consolidating Statements of Comprehensive Income (Loss)

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	147,964	$	(7,965	)	$	158,701	$	236,528		$	(387,264	)	$	147,964

Other comprehensive income (loss):
Foreign currency translation adjustment	—		—			—		17,466			—			17,466
Net loss on pension and other postretirement benefit adjustments, net of tax benefit	—		—			—		(6,170		)	—			(6,170		)
Net loss on cash flow hedges	—		(2,046		)	—		—			—			(2,046		)
Total other comprehensive (loss) income	—		(2,046		)	—		11,296			—			9,250
Comprehensive income (loss)	$	147,964	$	(10,011	)	$	158,701	$	247,824		$	(387,264	)	$	157,214

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Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	150,003	$	(3,916	)	$	156,037	$	224,142		$	(376,263	)	$	150,003

Other comprehensive income (loss):
Foreign currency translation adjustment	—		—			—		(8,243		)	—			(8,243		)
Net loss on pension and other postretirement benefit adjustments, net of tax benefit	—		—			—		(2,850		)	—			(2,850		)
Net gain on cash flow hedges	—		5,710			—		—			—			5,710
Total other comprehensive income (loss)	—		5,710			—		(11,093		)	—			(5,383		)
Comprehensive income	$	150,003	$	1,794		$	156,037	$	213,049		$	(376,263	)	$	144,620

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Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2018

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	444,233		$	100,385		$	179,512		$	514,936		$	(694,859	)	$	544,207
Cash flows from investing activities:
Capital expenditures	—			(71,044		)	(19,152		)	(367,256		)	—			(457,452		)
Change in accounts payable related to capital expenditures	—			11,101			(5,161		)	(13,623		)	—			(7,683		)
Acquisitions	—			—			(37,502		)	—			—			(37,502		)
Proceeds from insurance recoveries	—			—			—			78,419			—			78,419
Proceeds from sale of European operations	—			—			—			266,740			—			266,740
Proceeds from sale or disposition of assets	—			2,674			31			995			—			3,700
Investment in subsidiaries	(708,600		)	(1,711,975		)	(54,600		)	(54,665		)	2,529,840			—
Net cash used in investing activities	(708,600		)	(1,769,244		)	(116,384		)	(89,390		)	2,529,840			(153,778		)
Cash flows from financing activities:
Debt borrowings	—			1,840,853			—			31,800			—			1,872,653
Debt repayments	—			(2,349,476		)	—			(32,300		)	—			(2,381,776		)
Issuance of Series D preferred units	590,000			—			—			—			—			590,000
Payment of issuance costs for Series D preferred units	(34,203		)	—			—			—			—			(34,203		)
Issuance of common units, net of issuance costs	10,000			—			—			—			—			10,000
General partner contribution	204			—			—			—			—			204
Distributions to preferred unitholders	(90,670		)	(45,336		)	(45,336		)	(45,335		)	136,007			(90,670		)
Distributions to common unitholders and general partner	(300,777		)	(150,388		)	(150,388		)	(150,408		)	451,184			(300,777		)
Cash consideration for Merger (Note 4)	(67,936		)	—			—			141			—			(67,795		)
Proceeds from termination of interest rate swaps	—			8,048			—			—			—			8,048
Contributions from affiliates	—			599,400			54,600			1,768,172			(2,422,172		)	—
Net intercompany activity	162,498			1,766,881			77,996			(2,007,375		)	—			—
Other, net	(4,379		)	(1,101		)	—			(71		)	—			(5,551		)
Net cash provided by (used in) financing activities	264,737			1,668,881			(63,128		)	(435,376		)	(1,834,981		)	(399,867		)
Effect of foreign exchange rate changes on cash	—			—			—			(1,210		)	—			(1,210		)
Net increase (decrease) in cash and cash equivalents	370			22			—			(11,040		)	—			(10,648		)
Cash and cash equivalents as of the beginning of the period	885			29			—			23,378			—			24,292
Cash and cash equivalents as of the end of the period	$	1,255		$	51		$	—		$	12,338		$	—		$	13,644

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Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	483,481		$	152,101		$	102,405		$	405,950		$	(737,138	)	$	406,799
Cash flows from investing activities:
Capital expenditures	—			(47,600		)	(35,041		)	(301,997		)	—			(384,638		)
Change in accounts payable related to capital expenditures	—			(1,988		)	5,964			32,927			—			36,903
Acquisitions	—			—			—			(1,461,719		)	—			(1,461,719		)
Proceeds from Axeon term loan	—			110,000			—			—			—			110,000
Proceeds from insurance recoveries	—			—			—			977			—			977
Proceeds from sale or disposition of assets	—			1,955			18			63			—			2,036
Investment in subsidiaries	(1,262,000		)	—			—			(126		)	1,262,126			—
Net cash (used in) provided by investing activities	(1,262,000		)	62,367			(29,059		)	(1,729,875		)	1,262,126			(1,696,441		)
Cash flows from financing activities:
Debt borrowings	—			2,969,400			—			90,700			—			3,060,100
Debt repayments	—			(2,400,739		)	—			(86,800		)	—			(2,487,539		)
Issuance of preferred units, net of issuance costs	538,560			—			—			—			—			538,560
Issuance of common units, net of issuance costs	643,878			—			—			—			—			643,878
General partner contribution	13,737			—			—			—			—			13,737
Distributions to preferred unitholders	(38,833		)	(19,417		)	(19,416		)	(19,418		)	58,251			(38,833		)
Distributions to common unitholders and general partner	(446,306		)	(223,153		)	(223,153		)	(223,176		)	669,482			(446,306		)
Contributions from (distributions to) affiliates	—			1,262,000			—			(9,279		)	(1,252,721		)	—
Net intercompany activity	73,206			(1,801,218		)	169,223			1,558,789			—			—
Other, net	(5,708		)	(1,317		)	—			(300		)	—			(7,325		)
Net cash provided by (used in) financing activities	778,534			(214,444		)	(73,346		)	1,310,516			(524,988		)	1,276,272
Effect of foreign exchange rate changes on cash	—			—			—			1,720			—			1,720
Net increase (decrease) in cash and cash equivalents	15			24			—			(11,689		)	—			(11,650		)
Cash and cash equivalents as of the beginning of the period	870			5			—			35,067			—			35,942
Cash and cash equivalents as of the end of the period	$	885		$	29		$	—		$	23,378		$	—		$	24,292

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	391,773		$	167,900		$	211,816		$	359,283		$	(694,011	)	$	436,761
Cash flows from investing activities:
Capital expenditures	—			(64,334		)	(52,637		)	(87,387		)	—			(204,358		)
Change in accounts payable related to capital expenditures	—			(10,076		)	(285		)	(702		)	—			(11,063		)
Acquisitions	—			(95,657		)	—			—			—			(95,657		)
Investment in subsidiaries	—			—			(212,900		)	—			212,900			—
Net cash used in investing activities	—			(170,067		)	(265,822		)	(88,089		)	212,900			(311,078		)
Cash flows from financing activities:
Debt borrowings	—			1,365,529			—			41,200			—			1,406,729
Debt repayments	—			(1,419,852		)	—			(36,300		)	—			(1,456,152		)
Issuance of preferred units, net of issuance costs	218,400			—			—			—			—			218,400
Issuance of common units, net of issuance costs	27,710			—			—			—			—			27,710
General partner contribution	680			—			—			—			—			680
Distributions to common unitholders and general partner	(392,962		)	(196,481		)	(196,481		)	(196,501		)	589,463			(392,962		)
Contributions from affiliates	—			—			—			108,352			(108,352		)	—
Net intercompany activity	(241,131		)	255,326			250,487			(264,682		)	—			—
Other, net	(4,485		)	(2,354		)	—			(8,890		)	—			(15,729		)
Net cash (used in) provided by financing activities	(391,788		)	2,168			54,006			(356,821		)	481,111			(211,324		)
Effect of foreign exchange rate changes on cash	—			—			—			2,721			—			2,721
Net (decrease) increase in cash and cash equivalents	(15		)	1			—			(82,906		)	—			(82,920		)
Cash and cash equivalents as of the beginning of the period	885			4			—			117,973			—			118,862
Cash and cash equivalents as of the end of the period	$	870		$	5		$	—		$	35,067		$	—		$	35,942

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

28. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes quarterly financial data for the years ended December 31, 2018 and 2017:



	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Total
	(Thousands of Dollars, Except Per Unit Data)
2018:
Revenues	$	475,881	$	486,204	$	490,363		$	509,309		$	1,961,757
Operating income	$	98,480	$	79,838	$	95,277		$	89,968		$	363,563
Net income	$	126,133	$	29,399	$	48,136		$	2,126		$	205,794
Basic and diluted net income (loss) per common unit	$	1.15	$	0.15	$	(3.49	)	$	(0.31	)	$	(2.77	)
Cash distributions per unit applicable to common limited partners	$	0.60	$	0.60	$	0.60		$	0.60		$	2.40

2017:
Revenues	$	487,430	$	435,488	$	440,566		$	450,535		$	1,814,019
Operating income	$	97,139	$	73,404	$	91,717		$	74,018		$	336,278
Net income	$	57,940	$	26,250	$	38,592		$	25,182		$	147,964
Basic and diluted net income per common unit	$	0.49	$	0.05	$	0.15		$	0.00		$	0.64
Cash distributions per unit applicable to common limited partners	$	1.095	$	1.095	$	1.095		$	1.095		$	4.380

The quarterly financial data in the table above includes the impact of the $78.8 million gain from hurricane insurance proceeds received in the first quarter of 2018 and the $43.4 million non-cash loss associated with the sale of our European operations in the fourth quarter of 2018. Please refer to Note 1 for further discussion of the hurricane insurance proceeds and Note 5 for further discussion of the sale of our European operations.

Basic and diluted net income (loss) per common unit also includes the impact of the $377.1 million loss as a result of the Merger. Please refer to Notes 4 and 21 for further discussion.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of December 31, 2018.

INTERNAL CONTROL OVER FINANCIAL REPORTING


(a)	Management’s Report on Internal Control over Financial Reporting.

Management’s report on NuStar Energy L.P.’s internal control over financial reporting required by Item 9A. appears in Item 8. of this Form 10-K, and is incorporated herein by reference.


(b)	Attestation Report of the Registered Public Accounting Firm.

The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.


(c)	Changes in Internal Control over Financial Reporting.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

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PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required to be disclosed under this Item 10 is incorporated by reference to the following sections of our Proxy Statement for the 2019 annual meeting of unitholders, which is expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K (Proxy Statement): “Corporate Governance-Committees of the Board,” “Corporate Governance-Governance Documents and Codes of Ethics,” “Corporate Governance-Communications with the Board of Directors,” “Proposal No. 1 Election of Directors,” “Executive Officers” and “Security Ownership-Section 16(a) Beneficial Ownership Reporting Compliance.”

ITEM 11. EXECUTIVE COMPENSATION

Information required to be disclosed under this Item 11 is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Compensation Committee Interlocks and Insider Participation,” “Compensation Committee Report,” “Compensation Discussion and Analysis,” “Evaluation of Compensation Risk,” “Summary Compensation Table,” “Pay Ratio,” “Grants of Plan-Based Awards During the Year Ended December 31, 2018,” “Outstanding Equity Awards at December 31, 2018,” “Option Exercises and Units Vested During the Year Ended December 31, 2018,” “Pension Benefits for the Year Ended December 31, 2018,” “Nonqualified Deferred Compensation for the Year Ended December 31, 2018,” “Potential Payments Upon Termination or Change of Control” and “Director Compensation.”


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Information required to be disclosed under this Item 12 is incorporated by reference to the following sections of our Proxy Statement: “Security Ownership-Security Ownership of Management and Directors,” “Security Ownership-Security Ownership of Certain Beneficial Owners” and “Security Ownership-Equity Compensation Plan Information.”


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required to be disclosed under this Item 13 is incorporated by reference to the following sections of our Proxy Statement: “Corporate Governance-Director Independence,” “Corporate Governance-Committees of the Board” and “Certain Relationships and Related Party Transactions.”

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required to be disclosed under this Item 14 is incorporated by reference to the following sections of our Proxy Statement: “KPMG Fees” and “Audit Committee Pre-Approval Policy.”

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



(a)	(1	)	Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
			Management’s Report on Internal Control over Financial Reporting Reports of Independent Registered Public Accounting Firm (KPMG LLP) Consolidated Balance Sheets as of December 31, 2018 and 2017 Consolidated Statements of Income for the Years Ended December 31, 2018, 2017 and 2016 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016 Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016 Consolidated Statements of Partners’ Equity and Mezzanine Equity for the Years Ended December 31, 2018, 2017 and 2016 Notes to Consolidated Financial Statements
	(2	)	Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
	(3	)	Exhibits.
			The following are filed or furnished, as applicable, as part of this Form 10-K:



Exhibit Number	Description	Incorporated by Reference to the Following Document

2.01	Membership Interest Purchase and Sale Agreement, dated April 11, 2017, by and between NuStar Logistics, L.P., NuStar Energy L.P. and FR Navigator Holdings LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed April 11, 2017 (File No. 001-16417), Exhibit 2.1

2.02	Agreement and Plan of Merger, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 2.1

3.01	Amended and Restated Certificate of Limited Partnership of Shamrock Logistics, L.P., effective January 1, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.3

3.02	Amendment to Certificate of Limited Partnership of Valero L.P., dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Current Report on Form 8-K filed March 27, 2007 (File No. 001-16417), Exhibit 3.01

3.03	Eighth Amended and Restated Agreement of Limited Partnership of NuStar Energy L.P., dated as of July 20, 2018	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.1

3.04	Amended and Restated Certificate of Limited Partnership of Shamrock Logistics Operations, L.P., dated as of January 7, 2002 and effective January 8, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.8

3.05	Certificate of Amendment to Certificate of Limited Partnership of Valero Logistics Operations, L.P., dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03

3.06	Certificate of Amendment to Certificate of Limited Partnership of NuStar Logistics, L.P., dated and effective as of March 18, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.09

3.07	Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., dated as of April 16, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9

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Exhibit Number	Description	Incorporated by Reference to the Following Document

3.08	First Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., effective as of April 16, 2001	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1

3.09	Second Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., dated as of January 7, 2002	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10

3.10	Certificate of Limited Partnership of Riverwalk Logistics, L.P., dated as of June 5, 2000	NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7

3.11	First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P., dated as of April 16, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16

3.12	Certificate of Formation of Shamrock Logistics GP, LLC, dated as of December 7, 1999	NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9

3.13	Certificate of Amendment to Certificate of Formation of Shamrock Logistics GP, LLC, dated as of December 31, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14

3.14	Certificate of Amendment to Certificate of Formation of Valero GP, LLC, dated March 21, 2007 and effective April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02

3.15	Second Amended and Restated Limited Liability Company Agreement of NuStar GP, LLC, dated as of July 20, 2018	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 3.2

4.01	Indenture, dated as of July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities	NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1

4.02	Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated as of July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P., Valero L.P., Kaneb Pipe Line Operating Partnership, L.P., and The Bank of New York Trust Company, N.A.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02

4.03	Instrument of Resignation, Appointment and Acceptance, dated March 31, 2008, among NuStar Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline Operating Partnership, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05

4.04	Fifth Supplemental Indenture, dated as of August 12, 2010, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-16417), Exhibit 4.3

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Exhibit Number	Description	Incorporated by Reference to the Following Document

4.05	Sixth Supplemental Indenture, dated as of February 2, 2012, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed February 7, 2012 (File No. 001-16417), Exhibit 4.3

4.06	Seventh Supplemental Indenture, dated as of August 19, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed August 23, 2013 (File No. 001-16417), Exhibit 4.3

4.07	Eighth Supplemental Indenture, dated as of April 28, 2017, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4

4.08	Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee, relating to Subordinated Debt Securities	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1

4.09	First Supplemental Indenture, dated as of January 22, 2013, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Parent Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor, and Wells Fargo Bank, National Association, as Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2

4.10	Registration Rights Agreement, dated as of June 29, 2018, by and among NuStar Energy L.P. and the Purchasers party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 4.2

10.01	Amended and Restated 5-Year Revolving Credit Agreement, dated as of October 29, 2014, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, SunTrust Bank and Mizuho Bank, Ltd., as Co-Syndication Agents, Wells Fargo Bank, National Association and PNC Bank, National Association, as Co-Documentation Agents, and J.P. Morgan Securities LLC, SunTrust Robinson Humphrey, Inc., Mizuho Bank, Ltd., Wells Fargo Securities, LLC and PNC Capital Markets LLC, as Joint Bookrunners and Joint Lead Arrangers	NuStar Energy L.P.’s Current Report on Form 8-K filed October 31, 2014 (File No. 001-16417), Exhibit 10.1

10.02	First Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of March 19, 2015, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.01

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.03	Second Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of August 22, 2017, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed August 22, 2017 (File No. 001-16417), Exhibit 10.01

10.04	Third Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of November 22, 2017, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed November 22, 2017 (File No. 001-16417), Exhibit 10.01

10.05	Fourth Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of March 28, 2018, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.02

10.06	Fifth Amendment to Amended and Restated 5-Year Revolving Credit Agreement, dated as of June 29, 2018, among NuStar Logistics, L.P., NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 10.3

10.07	Lease Agreement Between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of July 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01

10.08	Letter of Credit Agreement dated June 5, 2012 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed June 12, 2012 (File No. 001-16417), Exhibit 10.01

10.09	First Amendment to Letter of Credit Agreement, dated as of June 29, 2012, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed July 6, 2012 (File No. 001-16417), Exhibit 10.2

10.10	Second Amendment to Letter of Credit Agreement, dated as of January 17, 2013, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.10

10.11	Third Amendment to Letter of Credit Agreement, dated as of March 8, 2013, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.11

10.12	Fourth Amendment to Letter of Credit Agreement, dated as of April 19, 2013, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Corporate Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.12

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.13	Fifth Amendment to Letter of Credit Agreement, dated as of April 23, 2014, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.13

10.14	Sixth Amendment to Letter of Credit Agreement, dated as of November 3, 2014, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.1

10.15	Seventh Amendment to Letter of Credit Agreement, dated as of April 30, 2015, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.02

10.16	Eighth Amendment to Letter of Credit Agreement, dated as of May 6, 2016, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.01

10.17	Ninth Amendment to Letter of Credit Agreement, dated as of April 17, 2017, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.03

10.18	Tenth Amendment to Letter of Credit Agreement, dated as of April 10, 2018, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and Mizuho Bank, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2018 (File No. 001-16417), Exhibit 10.07

10.19	Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of December 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.01

10.20	Letter of Credit Agreement dated as of September 3, 2014 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed September 9, 2014 (File No. 001-16417), Exhibit 10.1

10.21	Amendment No. 1 to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of November 3, 2014 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.3

10.22	Maturity Extension Letter (Amendment No. 2) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of August 19, 2015 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2015 (File No. 001-16417), Exhibit 10.01

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.23	Maturity Extension Letter (Amendment No. 3) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of July 15, 2016 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.02

10.24	Maturity Extension Letter (Amendment No. 4) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of July 13, 2017 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2017 (File No. 001-16417), Exhibit 10.02

10.25	Maturity Extension Letter (Amendment No. 5) to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of July 12, 2018 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and MUFG Bank, Ltd. (formerly known as The Bank of Tokyo Mitsubishi UFJ, Ltd.), as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2018 (File No. 001-16417), Exhibit 10.05

10.26	Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of August 1, 2011	NuStar Energy L.P.’s Current Report on Form 8-K filed August 10, 2011 (File No. 001-16417), Exhibit 10.01

10.27	Letter of Credit Agreement dated as of June 5, 2013 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Nova Scotia, as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed June 11, 2013 (File No. 001-16417), Exhibit 10.01

10.28	Amendment No. 1 to Letter of Credit Agreement and Subsidiary Guaranty Agreement dated as of November 3, 2014 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and The Bank of Nova Scotia, as Issuing Bank and Administrative Agent	NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.2

10.29	Purchase and Sale Agreement, dated as of June 15, 2015, among NuStar Energy Services, Inc., NuStar Logistics, L.P., NuStar Pipeline Operating Partnership L.P. and NuStar Supply & Trading LLC, as Originators, NuStar Energy L.P., as Servicer, and NuStar Finance LLC, as Buyer	NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.1

10.30	Receivables Financing Agreement, dated as of June 15, 2015, by and among NuStar Finance LLC, as Borrower, the persons from time to time party thereto as Lenders and Group Agents, PNC Bank, National Association, as Administrative Agent, and NuStar Energy L.P., as initial Servicer	NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2

10.31	Omnibus Amendment, dated as of January 15, 2016, which is the First Amendment to the Purchase and Sale Agreement referenced above and the First Amendment to the Receivables Financing Agreement referenced above among the respective parties thereto	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.32	Second Amendment to Purchase and Sale Agreement, dated as of September 20, 2017, by and among the Originators listed therein, NuStar Energy L.P., NuStar Finance LLC, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01

10.33	Second Amendment to Receivables Financing Agreement, dated as of September 20, 2017, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02

10.34	Third Amendment to Receivables Financing Agreement, dated as of March 28, 2018, by and among NuStar Finance, LLC, as Borrower, NuStar Energy L.P., as initial Servicer, Mizuho Bank, Ltd. and PNC Bank, National Association	NuStar Energy L.P.’s Current Report on Form 8-K filed March 28, 2018 (File No. 001-16417), Exhibit 10.01

10.35	Series D Cumulative Convertible Preferred Unit Purchase Agreement, dated as of June 26, 2018, among NuStar Energy L.P. and the Purchasers party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 10.1

10.36	Purchase Agreement, dated as of June 26, 2018, by and between NuStar Energy L.P. and William E. Greehey	NuStar Energy L.P.’s Current Report on Form 8-K filed June 29, 2018 (File No. 001-16417), Exhibit 10.2

+10.37	NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of January 28, 2016	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.30

+10.38	First Amendment to the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, dated as of February 7, 2018	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.31

+10.39	Form of 2013 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.15

+10.40	Form of Restricted Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.28

+10.41	Form of 2017 Performance Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.01

+10.42	Form of 2018 Performance Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed July 25, 2018 (File No. 001-16417), Exhibit 10.1

+10.43	Form of Non-employee Director Restricted Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-16417), Exhibit 10.31

+10.44	Form of 2018 Non-employee Director Restricted Unit Award Agreement under the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.08

+10.45	NuStar GP Holdings, LLC Long-Term Incentive Plan, amended and restated as of April 1, 2007	NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007 (File No. 001-32040), Exhibit 10.04

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Exhibit Number	Description	Incorporated by Reference to the Following Document

+10.46	First Amendment to the NuStar GP Holdings, LLC Long-Term Incentive Plan, dated as of February 7, 2018	NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-32040), Exhibit 10.46

+10.47	Form of 2013 Restricted Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-32040), Exhibit 10.30

+10.48	Form of Phantom Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-32040), Exhibit 10.40

+10.49	Form of Non-employee Director Phantom Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar GP Holdings, LLC’s Annual Report on Form 10-K for year ended December 31, 2016 (File No. 001-32040), Exhibit 10.42

+10.50	Form of Converted Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed July 20, 2018 (File No. 001-16417), Exhibit 10.1

+10.51	Form of Restricted Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.06

+10.52	Form of Non-employee Director Restricted Unit Award Agreement under the NuStar GP Holdings, LLC Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.07

+10.53	NuStar Energy L.P. Annual Bonus Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18

+10.54	Form of NuStar Energy L.P. Amended and Restated Change of Control Severance Agreement	NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1

+10.55	Form of Executive Change of Control Waiver Agreement dated effective as of February 7, 2018	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.39

+10.56	Form of Non-employee Director Change of Control Waiver Agreement dated effective as of February 7, 2018	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2017 (File No. 001-16417), Exhibit 10.40

+10.57	NuStar Excess Pension Plan, amended and restated effective as of January 1, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.45

+10.58	Amendment to NuStar Excess Pension Plan, effective October 9, 2018	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.04

+10.59	NuStar Excess Thrift Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30

+10.60	Amendment to NuStar Excess Thrift Plan, effective as of January 1, 2017	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02

+10.61	Amendment No. 2 to NuStar Excess Thrift Plan, effective October 9, 2018	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2018 (File No. 001-16417), Exhibit 10.05

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.62	Assignment and Assumption Agreement dated March 1, 2016 between NuStar GP, LLC and NuStar Services Company LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed March 1, 2016 (File No. 001-16417), Exhibit 10.1

10.63	Amended and Restated Aircraft Time Sharing Agreement, dated as of September 4, 2009, between NuStar Logistics, L.P. and William E. Greehey	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24

10.64	First Amendment to Amended and Restated Aircraft Time Sharing Agreement, dated as of August 18, 2017, between NuStar Logistics, L.P. and William E. Greehey	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02

10.65	Support Agreement, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 10.1

21.01	List of subsidiaries of NuStar Energy L.P.	*

23.01	Consent of KPMG LLP dated February 28, 2019	*

24.01	Powers of Attorney (included in signature page of this Form 10-K)	*

31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer	*

31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer	*

32.01	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal executive officer	**

32.02	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal financial officer	**

101.INS	XBRL Instance Document	*

101.SCH	XBRL Taxonomy Extension Schema Document	*

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	*

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*

101.LAB	XBRL Taxonomy Extension Label Linkbase Document	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*

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*	Filed herewith.

**	Furnished herewith.

+	Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(c) of Form 10-K.

An electronic copy of this Form 10-K is available on our website, free of charge, at http://www.nustarenergy.com

(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without

charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K

may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to

Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or

corporatesecretary@nustarenergy.com.

ITEM 16. FORM 10-K SUMMARY

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.




NUSTAR ENERGY L.P.
(Registrant)

By:	Riverwalk Logistics, L.P., its general partner
	By: NuStar GP, LLC, its general partner

By:	/s/ Bradley C. Barron
	Bradley C. Barron
	President and Chief Executive Officer
	February 28, 2019

By:	/s/ Thomas R. Shoaf
	Thomas R. Shoaf
	Executive Vice President and Chief Financial Officer
	February 28, 2019

By:	/s/ Jorge A. del Alamo
	Jorge A. del Alamo
	Senior Vice President and Controller
	February 28, 2019

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ William E. Greehey	Chairman of the Board	February 28, 2019
William E. Greehey

/s/ Bradley C. Barron	President, Chief Executive	February 28, 2019
Bradley C. Barron	Officer and Director (Principal Executive Officer)

/s/ Thomas R. Shoaf	Executive Vice President	February 28, 2019
Thomas R. Shoaf	and Chief Financial Officer (Principal Financial Officer)

/s/ Jorge A. del Alamo	Senior Vice President and Controller	February 28, 2019
Jorge A. del Alamo	(Principal Accounting Officer)

/s/ J. Dan Bates	Director	February 28, 2019
J. Dan Bates

/s/ William B. Burnett	Director	February 28, 2019
William B. Burnett

/s/ James F. Clingman, Jr.	Director	February 28, 2019
James F. Clingman, Jr.

/s/ Dan J. Hill	Director	February 28, 2019
Dan J. Hill

/s/ Jelynne LeBlanc-Burley	Director	February 28, 2019
Jelynne LeBlanc-Burley

/s/ Robert J. Munch	Director	February 28, 2019
Robert J. Munch

/s/ W. Grady Rosier	Director	February 28, 2019
W. Grady Rosier

146